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f 2 A 




FEB 1 01984 1 U / 


1515 E. 6th AVE. 


Prepared for 


R7 1984 

W Si 1990 

WG 1 J 1993 


S621.312N7lmb 1983d Bnce M " * 

A three megawatt biomass-firecl cogenerat 

3 0864 00047824 1 

OCT 2^005 


Prepared by 

Miller Brice 
Flodin Lumber and Manufacturing Company 
P.O. Box 309 
Plains, MT 59859 

July, 1983 

Prepared for 

Montana Department of Natural Resources and Conservation 
32 South Ewing, Helena, Montana 59620 
Biomass Utilization and Cogeneration Program 
Contract Agreement Number ED-FL-651 

Available on loan from 

Montana State Library, 1515 East Sixth Avenue 
Justice and State Library Building, Helena, Montana 59620 

This report was prepared under an agreement funded by the Montana Department of 
Natural Resources and Conservation. Neither the Department, nor any of its 
employees makes any warranty, express or implied, or assumes any legal liability or 
responsibility for the accuracy, completeness, or usefulness of any information 
apparatus, product, or process disclosed, or represents that its use would not 
infringe on privately owned rights. Reference herein to any specific commercial 
product, process, or service by trade name, trademark, manufacturer, or otherwise, 
does not necessarily constitute or imply its endorsement, recommendation, or 
favoring by the Department of Natural Resources and Conservation or any employee 
thereof. The reviews and opinion of authors expressed herein do not necessarily 
state or reflect those of the Department or any employee thereof. 



Designation No. 


Fuel Handling Process Diagram . . 



Heat Balance Diagram 

40x3011B-M203 Sh.l 


Heat Balance Diagram 

40X3011B-M203 Sh.2 


Energy Balance 



General Arrangement 



Flow Di agram—Condensate, Feedwater 

and Steam 



Flow Di agram--Mi seel 1 aneous Systems 





STPP-82 Supp.#l 


LTPP-82 Sudd #1 


Equipment and Material Cost Summary 




1 HDLC — £ 

/ D 

TARI F c i-'? 
1 nDUL *>— 


Sensitivity Analysis ROI vs. Electrical Rate 

r IbUKt D-l 


Sensitivity Analyis ROI vs. Capital 

Cost . . 



TABLE 5-4 


Plot Plan 



TABLE 6-1 





TABLE 8-1 







2.1 Fuel Available 5 

2.1 Fuel Required 8 

2.3 Fuel Handling Process Description 10 


3.1 General Plant Description 16 

3.2 Steam Generation System 24 

3.3 Power Generation System 26 

3.4 Steam Generator and Auxiliary Equipment 34 


3.5 Steam Turbine Generator and Auxiliary Equipment 38 


3.6 Balance of Plant Equipment Description 40 

3.7 Electrical System and Equipment Description 50 

3.8 Electrical Generation 54 

3.9 Existing Plant Electrical Requirements 55 


4.1 Regulatory Analysis 56 

4.2 Tax Incentives 63 

4.3 Utility Rate Schedules 65 

4.4 Utility Contract 72 


5.1 Power Plant Costs 73 

5.2 Cost Analysis 79 

5.3 Financing 89 


6.1 Siting 93 

6.2 Environmental 97 

6.3 Scheduling 102 

6.4 Permitting 104 




8.1 Used Equipment 

8.2 Assumptions 

8.3 References 

8.4 Power Purchase Agreement 


Flodin Lumber and Manufacturing Company presently owns and operates 
a sawmill near Thompson Falls, Montana, which produces approxi- 
mately 14 to 17 million board feet of lumber a year. The existing 
facility consists of two head rigs, planer mill, storage facili- 
ties, three dry kilns and a steam boiler plant. The boiler plant 
consists of two 40-year old wood fired boilers supplying process 
steam to the kilns. These antiquated boilers have been derated and 
are due shortly for replacement. 

This report investigates the feasibility of replacing these boilers 
with a larger boiler capable of supplying high pressure steam to a 
turbine generator in addition to the dry kilns. The resultant 
power produced and sold to the utility is used to offset the ini- 
tial capital investment. 

The plant size and configuration of the proposed biomass fired 
cogeneration facility, including detail systems and equipment 
description, are presented in Section 3.0. The capital costs for 
the design supply and construction of the plant are itemized in 
Section 5.0. 

The burning of wood waste in a power boiler for the production of 
steam and power is a proven technology. Due to the relatively 
small size of the cogeneration facility, the environmental permit- 
ting of the plant should be straightforward with no unforseen 
problems anticipated. Other pertinent planning and implementation 
considerations for the installation of the plant are described in 
Section 6.0. 

The majority of the wood to be fired will be generated on site at a 
relatively low price as a byproduct of the sawmill. The remaining 
fuel supply will be purchased from WI sawmill or other sources of 
shavings from adjacent mills. A detailed discussion of the wood 
byproducts and proposed wood handling system is qiven in Section 


From the economic analysis performed herein, the installation of 
the biomass fired boiler and 3 1/2 MW (gross) steam turbine genera- 
tor facility is an economically attractive and viable investment 
for Flodin Lumber and Manufacturing Company to consider making. 
Legislation which encourages cogeneration as a viable option for 
companies to pursue are explained in Section 4.0. 

Since the economic feasibility of the project is predicated on its 
source of revenue, the sensitivity of changes in the rate of which 
Montana Power Company (MPC) purchases power from qualifying cogen- 
eration facilities is considered. Based on the long term power 
purchase schedule presently in effect, the after tax return on 
investment (ROI) for the cogeneration plant investment is approxi- 
mately 26 percent. 

Currently, MPC is contesting to the Montana Public Service Com- 
mission the full avoided cost of S0.0533/KWH plus capacity payment 
published in Schedule #LTPP-82. From figure 5-1, if the composite 
electrical rate is reduced by the Public Service Commission from 
$0.0641/KWH to S0.04/KWH, the ROI is decreased from 26 percent down 
to 13 percent. Even with this significant reduction in the ROI, an 
after tax ROI of 13 percent is still within the minimum acceptable 
rate of return established by Flodin Lumber (i.e. MARR = 12 to 
15 percent . ) 


To determine the quantity of fuel required, it was first neces- 
sary to evaluate the present steam generation capacity and use at 
Flodin Lumber and Manufacturing Company. The second step was to 
determine the quantity of steam required for the power genera- 

The Flodin Lumber sawmill has two existing 40-year old, 125 
horsepower boilers supplying process steam to the kilns. The 
fuel for these boilers is sawdust and shavings obtained from the 
sawmill operation. According to the boiler operator, the boiler 
was originally rated at 125 psig, but has since been derated to 
100 psig. The steam pressure ranges from 60 psig, when the kilns 
are started up, to 90 psig during normal operation. The maximum 
combined output of both boilers is estimated to be less than 
7,000 lbs. per hour. The boiler is normally operated with 
natural draft only, with the forced draft fans started when 
necessary. With a steady fuel feed, the operator controls steam 
flow with manual operation of the inlet and outlet dampers. 
Flodin management has indicated that under severe conditions the 
two boilers were not able to handle the existing lumber dry kilns 
on startup. Under normal operating conditions, one existing 
boiler can carry the dry kiln load with surplus capacity. 

Since the existing boilers would be replaced by the cogeneration 
facility, the new steam generator will be sized to handle the 
existing steam requirements in addition to the steam required for 
electrical power generation. The mass and heat balance for the 
thermal cycle is depicted on drawing No. 40X3011B-M203 included 
herein under Section 3.1. The steam generation requirements for 
the nominal 3000 KW (3500 KW gross output) cogeneration plant are 
tabulated below: 


(600 PSIG, 750°F) 

3500 KW Steam Turbine Generator 

38,220 lb/hr 


3,902 lb/hr 

Dry Kilns (average) 

2,900 lb/hr 


45,022 lb/hr* 

The dry kiln flow is an estimated average for year around operation. 
During startup of the kilns and other intermittent modes of operation 
where the process steam demand exceeds the average flow, the throttle 
steam flow to the turbine will be reduced accordingly with an associated 
reduction in power generation. 

In addition to the 3 MW cogeneration plant, this section of the report 
will consider the availibility and requirements of fuel to support the 
operation of a 5 MW cogeneration plant. Henceforth, the 3 MW cogenera- 
tion plant will be referred to as the base case and the 5 MW cogeneration 
plant as the alternate case. 

*Feedwater flow, as shown on drawing No. M203, is greater than the super- 
heater outlet flow due to blowdown from the boiler drum. 



It was determined that there are four major sources of fuel in the 
Thompson Falls Area. These are: 

1. Flodin Lumber, Thompson Falls 

2. WI, Thompson Falls 

3. Louisiana Pacific, Trout Creek 

4. Purchased hogged dead Lodge Pole Pine 

For Flodin Lumber, it was determined that there are two basic 
operations throughputs from which the potential fuel production 
quantities should be calculated. The first basis would be to 
assume 1 1/2 shift per day for a 5 day week using present opera- 
ting througputs. The second basis is to assume that the planned 
21.4% increase in throughput is realized by 1984. 

In estimating the fuel available from Flodin, the following mate- 
rial was used: 

1. Computer printouts of sales to Louisiana Pacific, 
Missoul a. 

2. Quantities estimated by Flodin management. 

3. Calculated quantities of fuel burned in the existing 
boiler plant. 

4. An evaluation of the existing mill operations modified by 
standard "rule of thumb" estimates. 

For WI in Thompson Falls, the fuel available was assumed to be 
equal to that sold to LP, Missoula, plus surplus hogged fuel 
presently burned in tepee burners. The fuel availability numbers 
were modified to include a steady operation at one shift per day 
for a five day week. 

For LP, the production from Trout Creek was estimated by Trout Creek 
personnel . 

For the purchased hogged dead Lodgepole pine, it was assumed that a 
contractor would deliver the fuel directed to the steam generation facil- 
ity. Data from other dead Lodgepole pine operations indicate that the 
fuel will arrive at the plant site with an average of 33 percent H2O 
content. Operations at LaGrande, Oregon show a 25 percent moisture con- 
tent in chips derived from dead Lodgepole pine. No purchased hogged 
Lodgepole pine is used in the base because of the close proximity of the 
shavings available from WI, Thompson Falls. For the alternate case, the 
dead Lodge-pine is used for that quantity of fuel required above that 
supplied by Flodin and WI shavings. Assuming a potential for plant 
interruptions at WI and LP, the purchased hogged Lodgepole pine is used 
for the balance of the fuel requirement. Under almost any circumstance 
more fuel is available than is required for the 5 MW alternate case. 

The following is a tabulation of the estimated quantities of fuel avail- 
able from each source: (tabulated in dry tons per year, moisture content 
and wet tons per year). 

Flodin Base Case (based on 1 1/2 shift per day per 5 day week): 

Tons/Yr JCH2O Tons/Yr 

Bone Dry Basis Wet Basis Wet Basis 

Shavings 4650 8.4 5076 

Sawdust 4650 40.0 7750 

Hogged Fuel 18095 45.0 32900 

Flodin Alternate Case (based on 1 1/2 shift per day per 5 day week) 

Shavings 5731 8.4 6257 

Sawdust 5800 40.0 9667 

Hogged Fuel 21973 45.0 39951 

WI, Thompson Falls (based on 1 shift per day per 5 day week) 

Shavings 4567 13.9 5304 

Hogged Fuel 29304 45.0 53280 

Louisiana Pacific, Trout Creek Mill (based on 1 shift per day per 5 day 
week ) : 

Shavings 8064 15.0 9487 

Sawdust 3360 50.0 6720 

Hogged Fuel 14784 55.0 , 32853 

Purchased Fuel (Hogged Dead Lodgepole pine): 

Hogged Fuel As Required 33.0 As Required 


2.2 Fuel Required 

The combustion techniques proposed for this facility are based 
on "Fuel Conditioning." "Fuel Conditioning" is defined as dry- 
ing with stack gases, removal of rock and other non-combustible 
and air classification. 

With this quality of fuel available from "Fuel Conditioning," it 
is possible to take advantage of proven "state of the art" com- 
bustion equipment. 

A portion (coarse material @ approximately 28 percent H2O) 
will be burned, using an air spreader stoker, on grates. The 
balance will be burned in a true suspension burner where the 
combustion takes place in the radiant section of the steam 

The following tabulation shows the fuel sources and quantities 
consumed (based on 340 operating days per year) - 

Base Case (3 MW production)- 

As Burned 

Tons/Yr #/Hr % H 2 #/Hr 

B.D. Basis B.D. Basis Wet Basis Wet Basis 

Flodin Shavings 

Flodin Sawdust 

Flodin Hogged Fuel (Fines) 

Flodin Hogged Fuel (Coarse) 

WI Shavings 





Alternate Case (5 MW production)- 

Flodin Shavings 

Flodin Sawdust 

Flodin Hogges Fuel (fines) 

Flodin Hogged Fuel (coarse) 

WI Shavinqs 

Purchased Fuel (fines) 

Purchased Fuel (coarse) 









1. For the Base Case, no purchased hogged dead Lodgepole pine is in- 
cluded. Only Flodin plus a portion of the WI shavings are required 
to satisfy fuel requirements. WI is close and a reliable fuel 
source. If WI is shut down, LP surplus or hogged dead Lodgepole pine 
is available. 

2. For the Alternate Case, Flodin fuel, plus WI shavings are combined 
with purchased hogged dead Lodgepole pine to make up the fuel re- 
quirement. Other surplus fuel from WI, Thompson Falls and LP, Trout 
Creek were not required, but remain as alternate fuel sources. 

3. Excess air for combustion at design conditions is specified at 10 
percent pulverized fuel combustion and 30 percent for coarse fuel 


Flodin species mix for their sawmill is approximately 50 percent 
Ponderosa, 25 percent Douglas fir and 25 percent Western larch with other 
species occasionally mixed in. 

The Flodin mix is used to calculate the lower heating value of the fuel 
and pounds of air for combustion per pound of wood burned. 

Lower Heating Value 

Mix Species BTU/# #Air/# Wood 

50% Ponderosa pine 8245 6.37 

25% Douglas fir 8095 6.29 

25% Western larch 8410 6.45 

8250 6.37 

Lodgepole pine heating values and combustion air requirements vary 
considerably. For the purposes of this study, the LHV and air require- 
ments are assumed to be the same as for the Flodin mix. 

Ash content of "Conditioned Fuel" should fall between 1.5 and 3.5 percent 
on a weight basis. 

Moisture contents of available fuels are shown in the tables included in 
this report. 


The contract between Montana Department of Natural Resources and Flodin 
dated 15 January 1983 calls for "Fuel Conditioning" using steam generator 
stack gases for drying. The heat and material balances calculated for the 
study were done on the basis of "Fuel Conditioning." The "Fuel Handling 
Process" diagram shows the heat and material balances calculated on the 
basis of "Fuel Conditioning." 

The central feature of "Fuel Conditioning" is the drying of the fuel. 
Several different types of driers are commercially available for drying wood 
particles. For this project, the calculations were made on the basis of 
using a Thompson single pass rotary drier manufactured by Rader Companies, 
Inc. of Portland, Oregon. This drier is particularly adapted to fuel drying 
and has demonstrated successful experience in this field. In addition to 
drying, "Fuel Conditioning" includes removal of non-combustibles and size 
separation of the fuel to permit better combustion of the fuel. 

A brief description of the proposed facility is as follows: Wet wood fuel 
is dried using the products of combustion from the steam generator as the 
heat source for drying. Noncombustibl es are removed and the dried wood fuel 
is separated into two fractions (coarse and light). The coarse fraction is 
burned on grates in the combustion chamber of a steam generator. The light 
fraction is further reduced in size and burned in the combustion chamber 
above the grates using a pulverized fuel suspension burner. This system 
provides for maximum benefits from dry fuel combustion and eliminates the 
necessity for fossil fuel. The quantity of steam generated is determined by 
the actual plant and turbine generator requirement. 

For the Base 3 MW Case, the following fuel supply is available: 

1. Flodin shavings 

2. Flodin sawdust 

3. Flodin Hogged fuel 

4. WI shavings 

1239 lbs/hr (8% moisture) 

1900 lbs/hr (40% moisture) 

8064 lbs/hr (45% moisture) 

1014 lbs/hr (13.9% moisture) 


J ■ I o _| O |__ HI i u. i I i 2_ 

< m I - O 1 O T U I u. I I 

Using the above fuel supply, the following flow scheme was laid out: 

The three wet wood streams are combined in the Hog Fuel Storage area and 
metered onto a conveyor which transfers the wet fuel to the inlet end of 
the Thompson drier. Hot stack gases from the steam generator are com- 
bined with the wet fuel at this point. 

The Thompson drier incorporates a rock separator which automatically 
removes rock and other heavy non-combustibles. This separation is 
accomplished through mechanical means. The Thompson drier incorporates a 
system of internal baffles to retain the fuel to be dried in the drier 
until the fuel reaches the desired moisture content. At the outlet of 
the drier is an air classifier type Settling Chamber which segregates the 
coarse fraction from the lighter fraction using the air classification 
principle. Coarse material does not dry as fast or as efficiently as 
smaller or thinner particles. The coarse material dries to a moisture 
content range of 25 to 35 percent. The light fraction dries to a mois- 
ture content in the range of 6 to 12 percent. 

The relative quantity of the light fraction vs. the coarse fraction is 
largely dependent on the physical shape of the incoming fuel. There is a 
limited control possible at the Settling Chamber to either increase or 
decrease the quantity of coarse material. However, small increases or 
decreases in the percent of fuel going to the coarse fraction does not 
greatly change the burning characteristics of the fuel. 

The coarse fraction from the air classifier is transferred pneumatically 
through a cyclone and an air lock into the Dried Hog Fuel Storage bin. 
The Dried Hog Fuel Storage bin may be replaced by a flat Dried Hog Fuel 
Storage area. The coarse fraction is then conveyed, on demand, to a 
Metering Bin located in the boiler house. The coarse fraction is burned 
at the bottom of the combustion chamber (on grates) of the steam 
generator using an air spreader stoker as the feeding mechanism. This 
system involves spreading the fuel over iron or ceramic grates. The 
coarse hog fuel is used as the base load heat input. 


The Light fraction from the Settling Chamber is pneumatically conveyed to 
the Dried Fines Storage Bin through a cyclone and an air lock. The light 
fraction from the drier is combined in the Dried Fines Storage bin with 
the dry Flodin shavings. 

The Flodin shavings are dry enough for dry fines firing and therefore are 
not dried in the drier but are transported directly to the Dried Fines 
Storage bin. 

From the Dried Fines Storage bin the light fraction is conveyed, on 
demand, to a Metering Bin. The light fraction is metered from the 
Metering Bin through a Hammermill into an air stream that blows the 
pulverized material through a pulverized fuel suspension burner into the 
combustion chamber of the steam generator. The pulverized fuel is burned 
in suspension in the radiant section of the steam generator. Additional 
combustion air is conveyed through the normal passages of the Dual Air 
Zone Pulverized Fuel Suspension Burner. The suspension burner used for 
this study is manufactured by the Coen Company of Burlingame, California. 

The drier has several basic control parameters. One is the quantity and 
size of the coarse fraction that is separated from the light fraction. A 
second control is the quantity of flue gases passed through the drier. A 
third and important control is the control that can be gained through the 
use of an economizer on the boiler feed water pumped to the steam generator. 
Using a bypass arrangement on the economizer, the flue gases may exit the 
steam generator at a higher or lower temperature. 

The steam generator specified for the Base Case is designed to produce 
approximately 45,000 lbs/hr of steam at 600 psig and 750" F. Throttle steam 
flow to the steam turbine generator is approximately 38,220 lb/hr with the 
remaining steam produced by the boiler serving the deaerator and dry kilns. 

The stack or flue gases exit the steam generator at approximately 500° F. 
Since combustion program provides for complete combustion of the fuel, 
only ash in the form of bottom ash or fly ash remains as a pollutant 


produced in the steam generator. A high efficiency multiple-cyclone 
separator is used to remove the fly ash particulate that escape with the is 
steam generator flue gases. The remaining heavier bottom ash removed from 
the grates and from the chamber under the grates. 

The system described above provides for better and more rapid control of 
steam generation, less pollution and lower operating cost than a normally 
fired wet hog fuel boiler. In the design, proposed herein, an air 
preheater, which would normally be installed on a wet hog fuel fired boiler, 
is not included. Instead, an economizer, which doesn't have the maintenance 
problems associated with air preheater, is provided for preheating the 
boiler feed water and as the control element in the operation of the drier. 

In the proposed combustion system, higher flame temperatures are achieved 
with the combination suspension and grate burning because the drier fuel 
burns with less excess air and because less heat is lost in the evaporation 
of the moisture in high moisture content fuels. The suspension burning 
gives a precise and rapid control of heat input. The combustion is 
complete, minimizing air pollution problems. The higher flame temperatures 
and smaller particle size in suspension burning aids combustion. The steam 
generator itself is less costly and more efficient because of the higher 
rate of radiation heat transfer. The steam generator will require less 
maintenance because of lower air velocities " in the convection chamber and 
because no air preheater is required. The ID Fan for the steam generator is 
smaller and consumes less power. 

This system permits the inclusion of a precise burner control and 
consequently, precise steam production. The pulverized fuel burned has 
combustion control characteristics similar to a conventional gas or oil 
burner. Gas or oil burning capability can be included at a minimum cost to 
provide for steam production when the wood fuel supply might be curtailed. 

The 5 MW cogeneration plant will be identical in the "Proposed Flow Scheme." 
But, the heat and material balance will be increased to satisfy the higher 


steam demand. The following fuel sources and quantities are used in the 
design of the 5 MW facility: 

1. Flodin shavings 

2. Flodin sawdust 

3. Flodin hogged fuel 

4. WI shavings 

5. Purchased hogged Lodgepole pine 

1527 lbs/hr (8% moisture) 
2370 lbs/hr (40% moisture) 
9971 lbs/hr (45% moisture) 

1316 lbs/hr (13.9% moisture) 
4843 lbs/hr (33% moisture) 

For the Alternate Case, the steam generator is designed to produce 70,000 
lbs/hr of steam at 600 psig and 750° F. 55,000 lbs/hr of the steam is used 
in the Steam Turbine Generator Unit. 8,700 lbs/hr of steam are available 
for dry kilns. 6,400 lbs/hr of steam is included in the overall calculation 
to represent heat loss, blowdown and a small safety factor. 



General Plant Description 

The proposed cogeneration plant consists of a wood fired steam generator 
coupled with a condensing steam turbine generator. The steam generator, 
rated to produce 45,000 lb/hr of steam at 600 PSIG and 750°F, supplies 
high pressure steam to the steam turbine generator, deaerator and wood 
drying kilns. Drawing No. 40X3011B-M203 depicts the thermal cycle for the 
generation of steam and power. 

The steam turbine converts over 38,220 lb per hour of high pressure steam 
into 3500 KW of electricity. As there are not any large steam consumers, 
and due to the low capital cost constraints of this project, the turbine 
will, in all probability, be a used full condensing type. Although the 
use of an automatic extraction for the kiln and deaerator steam 
requirements would result in additional electrical power output, it would 
limit the used turbine market and add complexity to the operation and 
maintenance of a machine in this size range. An uncontrolled extraction 
would be feasible for providing steam to the deaerator, but the 
fluctuations of the kiln steam would not be suited for that type 

Steam for the wood kilns is extracted from the main header and its 
pressure reduced to approximately 75 PSIG. A desuperheater designed for 
the maximum flow rate of 7000 lb per hour reduces the steam temperature to 
20°F above saturation, suitable for use in the kiln. The steam flow is 
regulated in accordance with the requirements of the kiln. 

Steam is used in the deaerator to remove any noncondensible gases 
entrained in the returned condensate. A control valve drops the steam 
pressure down to 5 PSIG and adjusts the normal flow rate of 3902 lb/hr 
according to the volume of condensate flowing into the deaerator. This 
deaerating steam also serves to preheat the condensate preventing thermal 
shock in the boiler and also improving the efficiency of the thermal 



System make-up will be required as steam is lost at the kilns and a 
certain portion of the condensate is discharged from the boiler 
steam drum to prevent a buildup of dissolved solids makeup will be 
pumped into the condenser hotwell from the condensate storage 

The new cogeneration plant will be located east of and in close 
proximity of the existing sawmill. The general arrangement of the 
major equipment comprising the new plant is shown on drawing No. 
40X3011-010. The equipment arrangement is a preliminary 
recommendation and can be easily modified to suit the requirements 
of the Customer. 

The cogeneration facility can be divided into three major systems: 
fuel handling, steam generation and power generation. The steam 
generation and power generation systems are described in detail in 
the following subsections of the report. The description of the 
fuel handling system is presented in Section 2.0. 

The thermal cycle as illustrated in Drawing M-203 with the kiln 
arranged in parallel with the steam turbine generator dbes not 
qualify as a "cogeneration facility" as defined under the Public 
Utility Regulatory Policies Act (PURPA) of 1978. Instead, the 
plant is classified as a "small power production facility". The 
following criteria for a qualifying small power producer as 
stipulated in the regulations are met: 

1. The size of the facility cannot exceed 80 megawatts. 

2. The primary energy source of the facility must be biomass 
waste, renewable resources, geothermal or combination, 
thereof, which constitutes 75 percent of the total energy 

In the event a used automatic extraction steam turbine can be 


found, where extraction steam from the turbine is supplied to the 
kilns as the source of heat, the plant would qualify as a 
"topping-cycle cogeneration facility under PURPA. The criteria 
established for this type facility are as follows: 

1. The useful thermal energy output of the facility must, 
during any calender year period, be no less than 5 percent 
of the total energy output. 

2. Since none of the energy input is natural gas or oil, the 
topping-cycle cogeneration facility will not be subject 
to any efficiency standard. 

In addition, a cogeneration facility or small power production 
facility must meet the ownership criteria as a qualification 
requirement. The ownership criteria states that either type 
"facility may not be owned by a person primarily engaged in the 
generation or sale of electric power." 

Even though the facility may be either a small power producer or a 
cogenerator depending on the steam turbine selected, this report 
will refer to the new facility as a cogeneration plant. 

The energy balance for the complete facility is shown on drawing 
no. 40X3011B-M205. The terminology used in the energy balance is 
defined in the PURPA regulations as follows: 

1. "Total energy input" means the total energy of all forms 
supplied from external sources; 

2. "Total energy output" of a topping-cycle cogeneration 
facility is the sum of the useful power output and useful 
thermal energy output; 

3. "Useful power output" of a cogeneration facility means the 
electric or mechanical energy made available for use, 
exclusive of any such energy used in the power production 


4. "Useful thermal energy output" of a topping-cycle 
cogeneration facility means the thermal energy made 
available for use in any industrial or commercial process 
or used in any heating or cooling application. 

As previously stated, if extraction steam from the steam turbine i 

used as the source of heat to the process (i.e. kiln) in lieu of 

using steam directly from the steam generator, the plant would be 
classified as a "topping-cycle cogeneration facility. 



The steam generation facility described herein can be divided into four 
distinct subsystems: fuel firing, steam generation, combustion air and 
gas, and ash handling. Descriptions of the equipment and major components 
of each subsystem are given in Section 3.4. 

3.2.1 Fuel Firing System 

As discussed in Section 2.0, the fuel firing system for the boiler 
consists of two fuel flow streams. A dried hog fuel storage bin feeds the 
coarse fraction of conditioned wood onto the furnace grate via an air 
spreader stoker. The light fraction of "conditioned" and pulverized fuel 
wood material is fed through a pulverized fuel suspension burner into the 
furnace combustion section where the fuel is burned in suspension in the 
radiant section of the steam generator. 

3.2.2 Combustion Air and Gas 

Combustion air will be admitted both above and below the boiler grate 
insuring complete combustion of the fuel. The undergrate air 
is supplied by the electric motor driven forced draft (FD) fan into the 
furnace under the water cooled grate. The balance of the combustion air 
is supplied by the over- fire air (OFA) fan and is admitted through the 
airswept feeders. This OFA system creates proper furnace turbulence and 
good combustion to limit environmental problems. 


After combustion of the fuel in the furnace, the products of combustion 
(flue gas) passes throuqh the convection sections of the boiler (i.e. 
superheater) and out the economizer section. The hot gases are conveyed 
through ductwork to the mu 1 1 i eye 1 one dustcol lector which reduces 
particulate emissions within acceptable limits. 

The flue gas then passes through a wood drier where heat is transferred to 
dry the incoming wet hogged fuel. Finally, the relatively clean and cool 
flue gas is discharged by the induced draft fan through the stack and out 
to atmosphere. Since the furnace is a balance draft type, the induced 
draft fan essentially pulls or "induces" the flue gas which is discharged 
by the induced draft fan through the stack and out to atmosphere. 

3.2.3 Steam Generation 

Hot feedwater from the turbine cycle is initially delivered to the 
economizer inlet. The economizer, which is a bare tube, counterflow type, 
adds sensible heat to the feedwater prior to entering the pressure parts 
of the boiler. The water then enters the boiler natural circulation 
system. The system comprises a steam drum, water drum, furnace water wall 
tubes, and front rows of the generating bank. The water is discharged 
from the steam drum down for recirculation to the steam generating 
circuits. The water rises through the furnace tubes, absorbing the 
radient heat from combustion process and is partially boiled. The 
resultant steam/water mixture is collected in the steam drum where the 
water and dry steam is separated by the drum internals. The saturated dry 
steam is subsequently piped to the superheater sections. Radiant and 
convection heat is transferred from the combustion gas to superheat the 
steam to the desired temperature of 750° F. 

A desuperheating section is utilized for controlling superheater steam 
outlet temperature within permissible limits. 



The power generation facility is composed of the following mechanical 
systems described hereafter. The flow diagrams of several of these piping 
systems are detailed on drawing No. 40X3011-M201 and M202. The equipment 
and other major components in each system are discussed in Section 3.6. 

3.3.1 Main Steam System 

The main steam system is designed to supply medium pressure, superheated 
steam from the superheater outlet of the steam generator to the stop valve 
on the steam turbine. 

The steam piping is designed for adequate drainage in order to prevent 
water induction into the turbine during start-up and unit trips. All low 
point drains are equipped with air operated drain valves. High point 
vents are located in the main steam piping to vent air during hydrostatic 
testing. Amain throttle-stop valve supplied with the turbine generator 
for emergency shutoff is located in the main steam piping that leads to 
the turbine. The stop valve is then connected to the turbine control 
valves via piping furnished by the turbine manufacturer. The control 
valve's function is to precisely regulate the speed and load of the 
turbine by controlling the steam flow into the turbine steam chest. 

A forged strainer is provided in the throttle-stop valve to prevent for- 
eign objects from entering the turbine. During initial operation, addi- 
tional fine mesh strainers are added to the permanent strainers. 

3.3.2 Condensate System 

As the steam expands through the steam turbine and flows into the conden- 
ser at a backpressure of 4 inches Hga, it produces electricity. After 


expansion through the steam turbine, this exhaust steam condenses on the 
condenser tubes and the resultant condensate is collected in the condenser 
hotwell. Vertical can type condensate pumps, taking suction from the 
hotwell, pumps the condensate into the deaerator. Makeup for the 
condensate storage tank is supplied to the condenser for cycle losses of 
condensate due to boiler blowdown, leakages, etc. 

As the condensate is sprayed into the deaerator, it comes in contact with 
5 PSIG steam, which not only heats the fluid, but removes any noncondens- 
ible gases which would result in boiler tube pitting and erosion. The 
deaerated condensate then cascades down into the horizontal storage tank. 

3.3.3 Feedwater System 

The feedwater system controls and delivers heated feedwater to the econo- 
mizer inlet of the steam generator under all modes of operation. 

Condensate water stored in the deaerator storage tank is pumped by one of 
the two full capacity boiler feed pumps to the steam generator. The 
second pump is used as a spare. Each pump is furnished with suction and 
discharge shutoff valves to permit isolation for a pump that is out of 
service. Discharge check valves are also provided to protect each pump 
from reverse flow. 

To protect each pump from damage during low load operation, individual 
automatic minimum recirculation lines are routed from the pumps and dis- 
charge back to the deaerator. 

Feedwater flow to the generator is regulated by a feedwater control valve 
by a two-element control system. 


Feedwater chemical treatment consists of automatic chemical addition and 
sampling to protect the boiler and feedwater tubes from corrosion and 
erosion. The quality of the boiler feedwater passing through the 
feedwater heater tubes will be limited to: 

A solution of hydrazine and ammonium hydroxide is fed into the deaerator 
outlet piping to remove residual dissolved oxygen from the feedwater and 
to control feedwater pH„ 

3.3.4 Condenser Air Evacuation System 

The condenser air evacuation system is required to evacuate all noncon- 
densibles and associated water vapor from the condenser to maintain the 
minimum steam condensing pressure. An adequate amount of water vapor must 
be vented to insure proper performance of the condenser and to produce 
reasonable velocities in order to minimize steam side corrosion within the 

Normal air removal or "holding" operation is by means of a twin element, 
two stage steam jet air ejector equipped with inter and after condenser. 
A hogging ejector is used to initially pull or "hog" a vacuum in the 

pH Range 




- 9.2 

1.0 ppm 
0.005 cc/1 


The system and equipment is designed in accordance with the 
recommendations of the Heat Exchange Institute, "Standards for Steam 
Surface Condensers." 

3.3.5 Circulating Water System 

The function of the circulating water system is to provide cooling water 
to the condenser for removal of the heat rejected from the plant steam 

The system is designed as a closed recirculting pressure system utilizing 
a cooling tower as a heat sink as opposed to an open system with its 
objectionable thermal pollution of the river. The cooling water flows 
throughout the system under a positive head imparted by the circulating 
water pumps. The water is taken from the cooling tower basin, passes 
through the condenser, is delivered to the top of the cooling tower, and 
then it descends by gravity through the tower, dissipating its heat. 
Makeup water is added to the system to compensate for system water losses 
due to evaporation, system blowdown and drift. 

The cooling tower 1s a mechanical draft type, consisting of two cells 
arranged in-Hne erected on a concrete basin. The tower will be equipped 
with appropriate freeze protection and reversing fans. A 20°F approach 
and 25°F range were assumed to minimize the size and cost of the cooling 
tower and condenser. This design will also allow increased electrical 
output when the actual wet bulb drops below design as lower cooling water 
temperatures cause a lower condenser pressure and increased the work done 
by the steam. The cooling tower basin volume, between the normal and low 
water levels is designed for five minutes storage at design flow of the 
circulating water pumps. 


The water flows from the divided cooling tower basin through a channel 
into the screen chamber located in the Circulating Water Pump House. The 
screen chamber is provided with screen guides for placement of the fixed 
screens, which are of fine mesh for removing debris which might enter the 
circulating water pump. 

After passing through the screens, the cleaned cooling water enters into 
the circulating water pump sump. 

Two nominal 50 percent capacity vertical circulating water pumps will be 
installed in the sump located in the Circulating Water Pump House. The 
pumps are designed to operate in parallel during normal operation, serving 
the requirements of the condenser cooling water system and closed cooling 
water system. 

The circulating water pump discharge lines which are equipped with a 
butterfly valve and a rubber expansion joint ties into a common header. 
The single circulating water line is routed underground to the inlet 
waterbox of the surface condenser. The circulating water passes through 
the condenser tubes and is collected in the condenser discharge water 
boxes. The discharge line from the condenser are connected into a common 
line which is then routed underground back to the cooling tower. 

3.3.6 Boiler Vents and Drains 

The boiler vents and drains system is designed to meet the following 

- To discharge saturated water from the boiler by continuous and/or 
intermittent blowdown, at a flow rate required to maintain an 
acceptable level of total dissolved solids in the drum. 


- To drain the boiler, when necessary. 

- To provide for filling and venting the boiler. 

- To provide for draining water and venting air and steam from the boiler 
during startup. 

The steam drum will be continuously blown down in order to control boiler 
water chemistry. The continuous surface blowdown flows from the steam 
drum through two isolation valves, a manually-operated angle valve and 
into the blowdown flash tank. The angle valve is provided in order that 
the blowdown flow rate can be manually regulated. 

Upon entering the blowdown tank, a portion of the flow will flash to steam 
which 1s vented to atmosphere. The remaining condensate is discharged 
from the tank through a loop seal, quenched with service water and then 
emptied into the contaminated waste system. 

Miscellaneous vents and drains are provided off the numerous steam and 
water headers in the boiler. The various boiler drains, where practical, 
are routed to the boiler blowdown tank. 

3.3.7 Turbine Drains System 

The turbine drain system serves to provide drainage for the turbine and 
associated piping. These drains include, but are not necessarily limited 
to, the following: 

-Steam chest drain 
-First stage shell drain 
-Inner valve steam drain 
-High pressure packing leak offs 
-Exhaust crossover drain 
-Exhaust casing drains 

To conserve the usage of demineral ized water for makeup, these drains are 
routed to the condenser to recover the condensate. 



One (1) balanced draft wood fired steam generator will be furnished. The 
unit will be designed to deliver 45,000 pounds per hour of steam at 600 
PSIG and 750°F at the superheater outlet. The steam generator will be 
supplied with the normal complement of standard accessories together 
with the additional accessories as described below: 

3.4.1 A water-cooled furnace and boiler enclosure of a gas-tight welded 
wall construction, including but not limited to the following: 

1. Furnace welded wall assemblies and headers. 

2. Stays, clamps and supports. 

3. Drain openings. 

4. Acid cleaning connections with blind flanges. 

5. Handholes in headers fitted with removable welded handhole caps 
with machined seats. 

6. Access and observation doors. 

7. Openings for fuel ports, overfire air ports, soot blower ports and 
draft sensing ports, etc. 

8. Provisions for thermocouples. 

9. Provisions for replacement of superheater tubes. 

3.4.2 A two drum, bent tube, open pass, balanced draft boiler complete 
with all the necessary fittings and connections. 

3.4.3 A complete superheater from the drum outlet to the non-return valve 
fitted with all connections and devices required. A desuperheati ng 
section shall be furnished, consisting of a spray nozzle 
(mechanically atomizing type), mixing section with an internal 
sleeve assembly and complete temperature control system. 


3.4.4 An economizer of the bare tube, counterflow type enclosed in a 
gas-tight steel casing. 

3.4.5 A complete fuel firing system will be furnished consisting of the 
following components: 

1. Cast Iron or ceramic grate 

2. Air spreader stoker 

3. Dual air zone pulverized fuel suspension burner 

4. Individual fuel metering bins with metering screws for 
both coarse fuel and pulverized fuel. 

5. Spreader stoker blower 

6. Pulverized fuel conveyor fan. 

3.4.6 One forced draft fan shall be provided to supply the required 
combustion air to the boiler. The fan will have a double inlet, 
double width, backwardly inclined blades with non-overloading 
characteristics and horizontal shaft complete with the following 


1. Inlet boxes 

2. Inlet vanes 

3. Inlet silencer 

4. Fan bearing assemblies 

5. Shift couplings and coupling guards 

6. Drive motor with sole plates 



The fan drive shall be squirrel cage induction motor, with 
TEFC enclosure, sleeve bearings, and NEMA Class B or better 
i nsul ation. 

3.4.7 One induced draft fan shall be provided to remove the products of 
combustion from the boiler. The fan will have a double inlet, 
double width, radial tip blades with 3/8" full width blade liners 
and accessories as follows: 

1. Inlet boxes 

2. Inlet dampers 

3. Outlet damper 

4. Fan bearing assemblies 

5. Shaft couplings 

6. Coupling guards 

7. Drive motor 

8. Motor sole plate 

The fan drive shall be squirrel cage induction motor, with 
TEFC enclosure, sleeve bearings, and NEMA Class B or better 

3.4.8 A mechanical dust collector will be mounted at the outlet of the 
economizer section to collect dust and flyash in the flue gas 
leaving the boiler. The collector shall be a high efficiency 
multicyclone type, complete, including, but not limited to the 
following components: 

L. Casing 

2. Hoppers 

3. Collecting elements 

4. Hopper level sensing 

5. Access doors 

6. Shop insulation 


3.4.9 One steel stack will be provided for discharge of the flue gas to 
atmosphere. The stack shall be self-supporting and shall include, 
but not limited to the following items: 

1. Stack 

2. Base bolting cage 

3. Ladder with safety cage 

4. Access door 

5. Painters trolley 

6. Gas duct connections 

3.4.10 A complete soot blowing system to serve the steam generating unit 
shall be included as part of the scope of supply. 

3.4.11 All structural steel, Insulation and lagging necessary for an 
outdoor unit. 

3.4.12 Access and maintenance platforms and walkways will be furnished as 

3.4.13 All necessary boiler trim will be supplied including boiler 

3.4.14 All ductwork and breeching for the steam generator will be 


3.5 Steam Turbine Generator and Auxiliaries Equipment Descriptions 

The steam turbine generator will be an indoor condensing unit. The overall 
plant capital costs were held down by selection of a used turbine 
generator(see Section 8.1) that is acceptable for the plant steam conditions 
of 600 PSIG and 750°F at a throttle flow about 38,220 pounds per hour. The 
unit selected is a General Electric turbine furnished with a 55 PSIG 
extraction and surface condenser with accessories, and its generator is 
rated at 3500 KW at 2400 volts, 3 phase, 60 Hz with a 0.80 power factor and 
is furnished with all accessories. The standard features and accessories 
provided with the turbine generator are described hereafter. 

3.5.1 Control and protective valve systems consisting of the following: 

1. Trip throttle valve equipped with hydraulic operator and 
integral steam strainer: 

2. Inlet control valves of a multiple, cam-operated, spring 
closed, and poppet-type design. 

3.5.2 Mechanical Hydraulic Control System 

3.5.3 Turbine Control Panel for remote mounting in the Control Room 
complete with all the standard control features. 

3.5.4 Complete lubrication oil system consisting of the following 

1. Main oil reservoir tank of a welded steel construction, 
furnished with motor driven vapor extractor, oil separator 
on vapor extraction suction, oil return tray and other 
standard accessories. 


2. Two full capacity shell and tube oil coolers with 5/8 inch 
OD, 18 BWG. 90-10 Cu-Ni tubes. The coolers are mounted on 
the tank. 

3.5.5 Direct Driven Excitation System will be included. 

3.5.6 Switchgear shall also be supplied with the unit. 



3.6.1 Condenser 

A single shell, two pass, divided water box condenser will be 
provided to condense 40,000 Ib/hr of steam flow exhausting from the 
steam turbine. 

The horizontal shop tubed condenser shall be supplied with a 
deaerating and storage hotwell equipped with a collecting type 
condensate connection to prevent passage of vapor into the 
condensate pumps suction in addition to anti-vortexing devices. 

The specification for the condenser is as follows: 




Cooling Tower 

3/4" 0D, 18 BWG, 15 ft. 
long (effective) 
90-10 Cu-Ni 
70-30 Cu-Ni* 


Type of condenser 

Back pressure - inches Hga 

Surface-sq ft 

Cooling water required - gpm 
Tube velocity - ft/sec 
Cooling water source 
Cooling water design temp - °F 
Water box test pressure - PSIG 

Tube material 


*For air cooler section 


The condenser will also be provided with the following accessories: 

a. Hot well gauge glasses 

b. Reinforced rubber expansion joint for turbine exhaust 

c. Set of special wrenches and tools 

d. Air leakage meter 

e. All the connections required for heater drains, steam drains, 
condensate pump recirc, etc. 

f. Atmospheric relief valve 

3.6.2 Cooling Tower 

A two-cell mechanical induced draft cooling shall be field erected and 
supported upon a reinforced concrete cooling tower basin. The basin 
shall be sized for adequate cooling water storage. The tower will be 
constructed of wood or fiberglass and will employ two motor driven fans 
for air circulation. The cooling tower specifications are tabulated 

Quantity 1 

Type Mechanical Induced Draft 


Number of Cells 


Wet Bulb Design Temperature ° F 
Approach Temperature, ° F 
Cooling Tower Range, ° F 
Cooling Water Flow 
Fan Horsepower 

3,000 GPM 
20 HP Each 





3.6.3 Deaerator and Storage Tank 

A deaerator and storage tank shall be supplied to obtain an effluent 
oxygen content of not more than 5 PPB and a CO2 content of zero. It 
shall be of the spray tray type vent condenser. The spray system shall 
be self regulating for varying flow rates. The tray systems shall be 
designed such that sudden load changes will not disturb the trays. The 
storage tank (feedwater surge tank) shall be composed of ASTM A-285 
Grade C and sized for a seven minute holding time. It shall be provided 
with a stilling water level baffling arrangement to produce a surface 
calming effect. The deaerator and storage tank shall be equipped with a 
relief valve, spring loaded vacuum breaker, gauge glasses, thermometers, 
vent condenser, Impingement baffles, sliding supports and pressure 

Quantity 2 
No. of shells 1 
Type Spray Tray 

Feedwater entering, lb/hr 41,724 lb/hr 

Feedwater leaving 47,392 lb/hr 

Recovered condensate 1,450 lb/hr 

Feedwater temperature out 228° F 

Steam pressure 5 PSIG 

Steam flow 3902 lb/hr 

Oxygen guarantee .005 cc/liter 

Storage tank capacity 10 minutes 

Design pressure 25 PSIG 

Design temperature 650° F 


3.6.4 Boiler Feed Pumps 

Two full capacity boiler feed pumps will take suction from the 
deaerator and deliver the feedwater to the boiler economizer. An 
automatically controlled recirculating line will be provided from each 
boiler feed pump discharge line to the deaerator to meet pump minimum 
flow requirements. 



Type fluid 
Specific gravity 
Motor HP 

2-100% capacity each 

Horizontal centrifugal 

90 qpm 

1950 ft. 



75 HP 


Impel lers 

Shaft Sleeves 
Type Fluid 
Specific Gravity 

Ductile Iron 
316 SS 
SAE 4140 
316 SS 

3.6.5 Circulating Water Pumps 

Two half capacity vertical circulating water pumps located in the 
cooling tower pump sump will be provided to serve the condenser cooling 
water requirements and the closed cooling water system. The 
specification for the pumps are as follows: 



Motor HP 

2-50% capacity each 
Vertical Centrifugal 
1500 gpm 
60 ft. 
60 HP 



Casing & Casing rings 

Impel ler 


Cast Iron 


Carbon Steel 

Shaft Sleeve 


3.6.6 Condensate Pumps 

Two 100% capacity condensate pumps will be provided to pump condensate 
from the condensate hotwell to the deaerator. The pump is a vertical 
type with closed or semi-closed type impeller equipped with renewable 
wear rings. A single condensate pump recirculation will be provided to 
satisfy pump minimum flow requirements. Each pump will be sized to 
supply 100 percent of the required condensate flow with all drains 
discharging to the condenser. The pump will be equipped with a vertical 
solid shaft drive motor designed for the dead load and thrust of the 

Quantity 2-100% capacity each 

Type Vertical Can 

Capacity (design) 80 gpm 


NPSH (available) 
Motor Horsepower 

165 ft. 
1 ft. 
7 1/2 HP 


Impel ler 
Bowl s 

Shaft and sleeves 


Steel or Cast Iron 
11 - 13% Chrome 


3.6.7 Condensate Make-up Pumps 

One condensate make-up pump will be provided to supply condensate from 
the condensate storage tank to the condenser hotwell in the event that 

the difference in pressure and head between the hotwell and storage tank 
is insufficient for gravity flow. 

Quantity 1 - 100% capacity each 

Type Horizontal Centrifugal 

Capacity 15 gpm 

3.6.8 Steam Jet Air Ejectors 

A twin element two-stage steam air ejector will be supplied to evacuate 
air and noncondensibles from the main condensers. The ejectors will be 
factory packaged units complete with intercondenser, aftercondenser and 
all necessary internal piping, fittings, relief valves and isolation 

3.6.9 Condensate Storage Tank 

One 16,000 gallon carbon steel condensate storage tank with plastic 
liner will be provided to store adequate demineralized water for 
approximately 12 hours make-up requirements for the turbine cycle. The 
effluent from the condensate storage tank shall normally flow by 
pressure differential into the condenser hotwell. One condensate 
make-up pump will be provided to transfer water when there is not 
sufficient differential pressure for gravity flow and to supply other 
demineralized water needs. 


Motor HP 

30 ft. 
1/3 HP 



Capacity @ 14.7 psia, 60* F 
Dry Air Flow 
Water Vapor Flow 
Rating Conditions 
Condenser Tube Material 

2 - 100% capacity each 

Condensing Two-Stage Steam Jet 

4 scfm 

18 lb/hr 

39.6 lb/hr 

1" Hga and 71.5° F 

Stainless Steel 


3.6.10 Boiler Continuous Blowdown Tank 

One ASME code stamped blowdown tank sized to handle continuous boiler 
blowdown for the boiler will be furnished. Flashed steam will be routed 
to atmosphere through a swartout head and the drain will be routed to the 
contaminated waste system. 

3.6.11 Demineral izer System 

The makeup demineral izer shall be designed to supply the plant with a 
sufficient quantity and quality of makeup water. The system will consist 
of two twin bed trains (two cation and two anion exchangers), one month 
caustic and acid storage tanks, regeneration pumps, and complete control 
package. Each exchanger vessel will be 30" in diameter with an 84" 
straight side and will be code stamped for 100 PSIG. Due to the 
relatively good quality of raw water, the unit will continuously process 
water for 38 hours before automatically swapping trains. This changeover 
may be initiated by the operator, timer, flow counter, or effluent 
conductivity monitor. The regeneration pumps will be the positive 
displacement diaphragm type and will be provided in sufficient quantity 
to provide a 100% backup or spare for each train. 

The makeup demi neral i zer will also be supplied with a 4000 gallon 
neutralization tank. The regeneration backwash will gravity flow into 
this tank where caustic and/or acid is metered to achieve a neutral waste 
suitable for disposal or possible plant utilization. The tank will be 9 ft 
in diameter by 12 ft long and will be supplied with ph monitor, acid and 
caustic pumps, controls, and an air grid mix system to ensure a homogenous 


3.6.12 Instrument Air System Equipment 

The instrument air system will consist of one air compressor and one air 
dryer to meet the instrument air requirements of the entire plant 
facility. The equipment specifications are as follows: 

Air Compressors 



Discharge Pressure 
Motor HP 

Air Dryer 


Inlet Capacity 
Outlet DewPoint 

3.6.13 Piping, Valves and Specialties 

All piping systems including valves and speciality items will be in 
accordance with ASME, ASTM, and NFPA codes and will be supplied with 
suitable materials and be of sufficient size consistent with the fluid 
flowing through them. 



Air cooled, lubricated, rotary 
100 scfm 
100 psig 
25 HP 

Controls, aftercooler, air 
receiver, and starter 


Heater Dessicant 
100 scfm 

Prefilter and afterfilter 

Water Piping 

Underground yard piping will be coated and wrapped carbon steel. 
Main Steam 

Main steam will be delivered from the boiler superheater outlet to the 
turbine throttle valves through carbon steel pipe A106 Grade B. 


Feedwater will be transferred from the boiler feed pump to the economizer 
inlet through carbon steel pipe (ASTM A106- Grade B). 


Condensate will be transferred from the condenser hotwell to the boiler 
feed pump suction through carbon steel pipe (ASTM A106- Grade B). 

Miscellaneous System 

Piping material suitable for the intended service will be provided for all 
the auxiliary piping systems. 

Val ves 

The following generic type valves will be specified suitable for the 
particular application or service: gate, globe, check, ball, butterfly, 
needle, safety and relief valves, etc. These valves will be furnished in 
the piping systems as necessary to serve the following functions: 

-isolation for inservice maintenance of equipment 
instruments, and control valves. 

-flexibility in system operation 

-protection of equipment and systems (such as prevention 
of reverse flow) 


Special i ties 

Strainers, steam traps, expansion joints, breakdown orifices and other 
piping specialities will be supplied as required for the piping systems. 

3.6.14 Insulation and Lagging 

All piping and equipment subject to temperatures above 140 °F will be 
insulated with the proper thickness and type of calcium silicate 
insulation to minimize heat loses. Where lines subject to temperatures 
above 140°F do not require insulation to minimize heat losses, such as 
flowoff lines, insulation will be provided in selected areas for personnel 
protection only. Metal jackets will be provided over the insulation, 
except where not practicable to do so. 

Prefab jacketing will be used for flanges, fittings and bends for 4 inch 
nominal pipe size or smaller. For larger fittings, valves, flanges, 
tanks and heaters, the aluminum jackets with vapor barrier will be field 
fabricated to follow the contour of the material being insulated. 

The insulation and jacketing for access doors, removable panels, manholes, 
bolted heater head joints, etc., will be done in a manner that will 
minimize damage to the insulation during access or maintenance periods. 

3.6.15 Control Valves 

Control valves will be furnished for sytems, subloops and individual 
services requiring modulating type controls. Control valve design and 
sizing will be predicated on best engineering practices to prevent 
flashing and cavitation for high quality, low maintenance components. 
The control valves shall include but not limited to the following. 

1. Condensate makeup control valves 

2. Condensate system minimum recirculation control valves 

3. Condensate dump valve 

4. Deaerator level control valve 

5. Boiler feed pump minimum recirculation control valves 

6. Feedwater level control valve 

7. Cooling tower basin level control valve 

8. Deaerator pegging steam pressure reducing valves 



System Interconnection 

The proposed electrical systems are shown on the one-line diagram E150. 

The system basically consists of (1) steam turbine connected to MPC. 
The primary point of delivery to MPC will be the 2,400 V side of the 
utility substation transformer rated at 5 MVA 54/2.4 K.V. 


The electrical system shown on the one-line diagram Drawing No. 
40X3011F-E150 is based on a generation capacity of 4375 K.V. A. at 0.8 
power factor 3500 kilowatts, 3 phase, 60 cycle. The generator will be a 
2-pole machine operating at 3600 R.P.M. and generating 2400 volts. The 
machine will be directly connected to a condensing turbine. It will be of 
the rotating field type with a rotary exciter and stationary voltage 
regulator. Load/speed control will be by governor. The generator will be 
wye-connected with the neutral grounded through a 2,400 volt to 240 volt 
distribution type, grounding transformer with a secondary resistance sized 
to limit the voltage at the generator bus to the minimum valve in the 
event of an arcing ground fault. The generator main bus will be a cable 
bus consisting of a number of 5 K.V. cables. The generator protection as 
shown on one-line diagram consists of: 








5 IN 


















The following metering is also provided: 









This switchyard will be owned and operated by MPC. It will consist of a 
2.4 K.V. to 54 K.V. transformer, a 54 K.V. oil circuit breaker and asso- 
ciated 54 and 2.4 K.V. isolating switches. Synchronizing will be done 
manually through the generator 2.4 K.V. breaker. This transformer will be 
oil-filled and located in the outdoor switchyard/substation. It will have 
a rating of approximately 5 MVA. It will be equipped with bushing-type 
current transformers to provide overcurrent, differential and ground fault 
protection. The 54 K.V. O.C.B. will be interlocked with the 2.4 K.V. 
generator circuit breaker. Plant operating power will be supplied by an 
oil-filled auxiliary transformer rated at 400 KVA and located outdoors. 
This transformer will transform 2.4 K.V. to the plant utilization voltage 
of 480 V. This transformer will be Delta connected on the 2.4 K.V. 
primary side and wye connected on the 480 V secondary side. 


In-Pi ant Systems 

Plant equipment and systems will be operated at 480/277 volts and 208/120 
volts. Motors 1/2 h.p. through 200 h.p. will operate at 480 volts and 
will be controlled and protected by the 480 volt motor control centers. 
The 480/277 volts systems will be supplied by the station auxiliary 
transformer. This will be throat connected and integrally mounted with 
the 480 volt switchgear. 

A 125 volt D.C. station-service battery system will be utilized to provide 
switchgear and protective-relaying operating power. In a turbine 
emergency, it will also provide power for the lube oil pump, turning gear, 
alarms, and annunciator systems and emergency lighting. The battery will 
have adequate capacity to bring the turbine-generator to a safe and 
orderly shutdown in an emergency. An automatic battery charger will be 
provided with ample capacity to charge the battery system from full 
discharge within 24 hours while carrying the normal operating load. The 
plant lighting system will, in general, operate from the 480/277 volt 
power system. Lighting levels will be in accordance with the Illumination 
Engineering Society of North American Standards. Emergency lighting will 
be provided from the station-service battery or individual, 
self-contained, batterypack type fixtures. The cables carrying 480 volts 
will be 600 V moisture and heat-resistant cross-linked synthetic polymer 
insulated cables. 



As stated previously, the gross output of the steam turbine generator is 
3500 K.W. In order to determine the net export of electricity to the 
utility, the plant auxiliaries and mechanical /generator losses have to be 
deducted from the gross output. 

The mechanical and generator losses for a turbine generator unit of that 
size is 100 KW. The plant auxiliaries required for operation of the 
cogeneration facility are estimted at 400 KW. 

Consequently, the net power output of the cogeneration plant is 3000 KW. 
Based on 8000 hours per year operation, the annual electrical generation 
will be 24,000,000 KWH. 



The electrical requirements of the existing sawmill facility have been 
previously served by MPC substation consisting of three 333 KVA 
transformers. MPC has recently uprated the substation by installing three 
833 KVA transformers in place of the smaller units. 

The proposed cogeneration plant will not effect the present interconnection 
between MPC and Flodin's sawmill since the electrical power output will be 
supplied to MPC transmission grid directly through a step-up transformer. 

Even though the cogeneration plant will not directly supply power to the 
sawmill facility, the monthly mill electrical useage and associated costs 
from March 1982 to July 1983 are given below for information only: 





MARCH, 1982 








































JANUARY, 1983 






























The addition of a new biomass (wood) fired boiler and turbine generator is 
a new venture for many industrials. In determining the feasibility of 
such a venture, a number of key elements should be addressed. 

The following discussion covers several of those elements for detailed 
consideration: regulatory analysis, tax incentives, utility contract and 
rate schedules. 

4.1 Regulatory Analysis 

Federal and state regulatory policies are a heavy influence on the 
feasibility of cogeneration projects. This Section will address 
these policies and their effect as positive and negative influences on the 
total program. 

Basically, these regulations were intended to encourage industrial steam 
and power generation through the use of fuels other than oil or gas. 
As envisioned, this mission was to be accomplished through smooth 
progression of laws which sought to provide incentives for energy 
conservation/ independence. 

However, the sought after "smooth progression" has proven more cumbersome 
than originally anticipated by the Department of Energy (DOE), due mainly 
to regulatory constraints that served as a disincentive to firms 
interested in cogeneration and small power production. To ease the impact 
of these constraints, the government, through DOE's Federal Energy 
Regulatory Administration (ERA), recently promulgated more favorable 
regulations governing the implementation of the Power Plant and Industrial 
Fuel Use Act (PIFUA) and the Public Utilities Regulatory Policies Act 
(PURPA). This then is an identification/analysis of the rules embodying 
those principles: 


The Power Plant and Industrial Fuel Use Act (PIFUA) 

Although this law does not exactly provide incentive to pursue alternate 
fuel use, it does encourage, a lesser dependence on oil and gas. This 
law, one of five comprised by the National Energy Act of 1978, has 
undergone continued scrutiny and revision. Among other things the law 

"An Owner must use alternate fuels (other than gas and oil) for all 
new boilers with a fuel input of greater than 100 MMBTU's (or for 
facilities with aggregate input greater then 250 MMBTU's) unless 
granted an exemption. 

'Existing facilities capable of conversion to coal must convert. 

"Existing facilities not capable of conversion may have to use a 
coal -oil mixture. 

"Switching from oil to gas is restricted. 

"In utility power plants, gas usage can be no larger a proportion of 
fuel used than it was during the period 1974-1976. 

"No Electric Utility use of gas after 1990. 

This law as originally drafted proved inflexible, and came under criticism 
from industry. As a result, DOE moved to simplify and streamline the 
regulations it set forth on an iterim basis for complying with the coal 
conversion requirement of PIFUA. Under recent DOE/ERA action the follow- 
ing prevails: 

"ERA has issued final regulations covering both new and existing 
industrial plants that make it considerably simpler for companies to 
obtain exemptions from the mandate to burn coal. 

"ERA has proposed new legislation that would ease the current "cost 
test" requirement that coal must be proved "substantially more expen- 
sive" to use than imported oil before an industrial plant can be 
excused from burning coal. 


These latest developments do not necessarily affect the Flodin Lumber and 
Manufacturing Company operation, but they do represent what might be 
perceived as a greater flexibility on the part of DOE in translating the 
law. Further, and regardless of the administration's latest stance, it 
should be recalled that although the intent of the law is many-fold, its 
primary purpose is to conserve natural gas and oil. The law specifies that 
these "premium" fuels shall be saved for uses for which there are no 
feasibile alternate fuels or raw material substitutes. The law encourages 
the greater use of coal /wood and other alternate fuels as a primary energy 
source in place of gas and oil. Realistically, it remains to be seen what 
long-term impact the law will really have, although it makes long-range 
energy planning a critical element in corporate well-being. 
The industrial user should certainly plan ahead with a view to adhering to 
the law. 

ERA also has made additional changes in the rules affecting cogenerators. 
For example: 

"On Cogeneration, specifically, DIE's interim-final regulations had 
required an applicant to show there would be "substantial" oil or gas 
savings before cogeneration would be considered as an alternative to 
coalcombustion. The new regulation established regional targets for 
cogeneration in an effort to promote the use of technology to displace 
significant portions of oil and gas on a regional, instead of 
site-specific, basis. DOE's proposed rule would allow up to 1312 MW 
of new oil-or gas-fired cogeneration in 11 states. In each case, the 
state governor would have to certify that the cogenerator was eligible 
to be included under the state limit imposed by DOE, although the 
state could petition the agency to raise the limit. 

"In an alternative proposal, ERA is also considering requiring 
certification by the state that the cogenerator would be displacing 
oil and gas, and that it could not use a coal/oil mixture as an 
alternate. DOE's proposal also significantly changes the method by 
which cogeneration would be computed, thus freeing more potential 
cogenerators from the restrictions placed on utilities and allowing 
additional units to be considered as industrial units. 

"DOE's regulations for new units contain far easier reporting 
requirements than were present in the original issuance of 
interim-final rules document. The new ruling essentially does away 
with the fuel decision report that had been criticized as overly 


burdensome. In place of that report, which required the applicant to 
survey all possible fuels and alternative generating methods, DOE will 
now require only that the applicant make a "good faith" effort to find 
adequate supplies of alternative fuels, and that he supply certain 
detailed information for the specific exemption that is sought. Under 
these regulations, all new industrial units must be built to burn a 
fuel other than oil or natural gas, unless they receive a DOE exemp- 

The aforementioned rulings by DOE clearly indicate that the government is 
moving on several fronts to relax regulatory and economic impediments to 
cogeneration, and that these moves when aligned with the PURPA incentives, 
represent significant gains for the cogenerator. 

The Public Utility Regulatory Policies Act (PURPA) 

Before enactment of PURPA, a cogenerator seeking to establish interconnec- 
ted operation with a utility faced three major obstacles. First, a util- 
ity was not generally required to purchase the output at an appropriate 
rate. Second, some utilities charged discriminatori ly high rates for 
back-up service to cogenerators. Third, a cogenerator which provided 
electricity to a utility's grid ran the risk of being considered an elec- 
tric utility; and thus being subjected to state and federal regulation as 
an electric utility. Such conditions removed the incentive for on-site 
power generation at the industrial user level. However, the inception of 
PURPA in 1978, and the final rule regarding the implementation of Section 
210 in February of 1980, has fostered a far different emphasis. The 
intent is now to encourage cogeneration by reducing regulatory obstacles. 
Under Section 210 of PURPA, cogeneration facilities that meet certain 
standards, and are not owned by persons primarily engaged in the genera- 
tion or sale of electric power can become qualifying facilities, and in so 
doing become eligible for the rates and exemptions set forth under Section 
210 of PURPA. 

The following is a series of relevant excerpts from the law as written: 

'Each facility is required under Section 210 of PURPA to offer to 
purchase available electric energy from cogeneration facilities which 
obtain qualifying status under Section 201 of PURPA. For such pur- 
chases, electric utilities are required to pay rates which are just 
and reasonable, and do not discriminate against the cogenerator. 


"Section 210 also requires electric utilities to provide electric 
service to qualifying facilities at rates which are just and 
reasonable, and are nondiscriminatory against cogenerators. 

"Such facilities as qualify, are entitled to avail themselves of the 
rate and exemption provisions under Section 210 of PURPA; also, 
qualifying cogeneration facilities are eligible for exemption from 
incremental pricing under Title II of the Natural Gas Policy Act of 

"Certain interconnection costs may be incurred as a result of sales 
from a utility to a qualifying facility. FERC prohibits the use of 
"unreasonable rate structure impediments, such as unreasonable 
hook-up charges or other discriminatory practices."* 

This prohibition is reflected in Section 292.306(a) of these rules, which 
provides that interconnection costs should be assessed on a 
nondiscriminatory basis with respect to other customers with similar load 
characteristics. In addition, state regulatory authorities (such as the 
Montana Public Service Commission) have the responsibility and authority 
to ensure that the interconnection requirements are reasonable, and that 
associated costs are legitimately incurred. 

"FERC finds that to require qualifying facilities to go through the 
complex procedures as set forth in Section 210 of the Federal Power 
Act to gain interconnection would, in most circumstances, 
significantly frustrate the achievement of the benefits of the PURPA 
program, if that Section was the exclusive means of obtaining 
interconnection. PURPA Section 210 thus provides that an electric 
utility must make any interconnections necessary to permit purchases 
from or sales to the qualifying cogeneration facility. 

"In the notice of the proposed rulemaking, FERC provided that each 
utility must offer to operate in parallel with a qualifying 
cogeneration facility, provided that the qualifying facility complies 
with standards established by the State Regulatory Authority or 
non-regulated electric utility with regard to the protection of 
system reliability pursuant to Section 292.308. By operating in 
parallel, qualifying facilities are enabled to export automatically 
any electric energy it does not use. 


A critical element of PURPA pertains to "avoided cost." It is this cost 
which must form the basis for negotiation with the utility. In essence, 
if, by purchasing electric energy from a qualifying cogeneration facility, 
a utility can reduce its energy costs (or can avoid purchasing energy from 
another utility) the rate for a purchase from the cogenerator is to be 
based on the energy costs the utility can thereby avoid. In a broader 
sense, "avoided cost" can be defined as the costs to an electric utility 
of energy or capacity (or both) which, but for the purchase from a 
qualifying cogenerator, the utility would generate, construct itself, or 
purchase from another source. This definition is derived from the concept 
of "the incremental cost to the electric utility of alternative electric 
energy" set forth in Section 210(d) of PURPA. 

Whereas the Montana Public Service Commission can (and does) set forth its 
assessment of full avoided cost, this number is not without challenge. As 
an example, MPC currently is seeking reassessment of full avoided cost. 
MPC maintains that the avoided cost is prohibitively high, and in response 
has filed a motion for reconsideration. This could result in a reduced 

At the federal level, the U.S. District Court in Washington, D.C. 
overturned the FERC rules on avoided costs in "American Electric Power 
versus FERC." In this January 1982 decision, the Court suggested that 
"the Commision take a harder look at especially the percentage of avoided 
cost approach" to allow the state commissions to set rates within a 
certain range (eg 80 to 100 percent of avoided cost). The key point in 
the Court's decision is that they did not find that full avoided cost was 

FERC has since petitioned for a stay of the decision while an appeal is 
made to the Supreme Court. Since the Supreme Court previously has ruled 
favorably on the constitutionality of PURPA, it is clear that the avoided 
cost basis established for utility purchase of cogenerated power will 
continue regardless of the outcome of the Supreme Court decision. 


The motion for reconsideration is not without meaning because it shows 
that negotiation between the utility and the cogenerator is not inflex- 
ible. In effect, an industrial cogenerator can enter with a utility into 
any contractural agreement that suits his interests or financial require- 
ments, using PURPA as a guideline. 

Clearly, cogeneration is "most favored" as a means of obtaining a measure 
of energy efficiency and independence. PURPA, assures the cogenerator 
a) he can sell electric energy on a full avoided cost basis, b) receive 
back-up power and purchase power at nondiscriminatory rates, (c) inter- 
connect on a legitimately incurred costs basis and, d) operate in paral- 
lel. The enactment of PURPA is rightly viewed as a major step in that it 
mandates certain "obligations" by the utility, and in so doing reduces the 
obstacles attendant to parallel generating operations. 



In the Energy Tax Act of 1978, Congress created tax incentives for 
alternative energy systems. These were expanded and modified in the Crude 
Oil Windfall Profit Tax Act of 1980. Subsequently, Congress enacted 
the Economic Recovery Tax Act of 1981 which provides some new incentives 
for all types of investments. 

There are three principal tax incentives which affect cogeneration 
projects. First, the regular investment tax credit applies to most 
cogeneration equipment. Second, the energy investment tax credit applies 
to biomass fired facilities. Third, the Economic Recovery Tax Act allows 
an accelerated depreciation schedule for rapid capital recovery. 

The regular investment tax credit is currently set at ten percent of the 
cost of a qualified investment. For a cogeneration project, the 
investment cost for all the components of industrial systems and 
equipment, excluding buildings, should qualify for the credit. 

The Energy Tax Act of 1978 specifically added a provision excluding 
industrial boilers fueled primarily by oil or natural gas from the regular 
tax credit. 

In addition to the regular investment tax credit, the legislation allows 
for an additional 10 percent credit for certain classes of energy 
property, two of which are relevant to cogeneration projects: biomass 
property and cogeneration equipment. The provision for energy investment 
credit for cogeneration equipment expired on December 1982. For biomass 
property, the credit is allowed through 1985. 


Biomass property is defined as a boiler or burner that uses some substance 
other than oil, gas or coal, or products thereof, as more than half its 
fuel. Equipment for conversion of such a substance into solid synfuel or 
alcohol also qualifies for the additional tax credit. 

The credit for a qualifying boiler normally would extend to the associated 
fuel handling and pollution control equipment. 

The 1981 Economic Recovery Tax Act established a new Accelerated Cost 
Recovery System (ACRS), whereby qualifying equipment can be written off in 
five years and most buildings in fifteen years, independent of their 
physical lives governed under the preexisting IRC Section 167 rules for 
Asset Depreciation Ranges (ADR). 

The biomass property should qualify for the accelerated cost recovery 
system, and as such, its depreciation schedule for a five-year writeoff 
is: 15, 22, 21, 21, 21 percent. 



The Montana Public Service Commission has approved two different tariff 
schedules which MPC uses for the calculating of payment to qualifying 
cogeneration (COG) or Small Power Producer (SPP) for the sale of 
electricity to MPC. The following conditions must be met: 

1) Operates a Qualifying COG/SPP facility in accordance with the 
rules and regulations for COG/SPP Sellers; 

2) Has signed the standard contract with the MPC stipulating the 
terms and conditions of the inter-connection and sale of 
electricity to MPC; 

3) Has agreed in the standard contract to provide electricity to the 
Montana Power Company either on a short or long term basis. 

The two different tariff schedules in effect are for Short Term Power 
Purchases (STPP) and Long Term Power Purchases (LTPP) which are included 
herein as Schedule STPP-82-Supplement #1 and Schedule LTPP-82, 
respectively. For STPP the seller agrees to commit the electrical output 
of the facility to MPC for a period of at least one year. The seller is 
paid for the net generation of power (kilowatt hours) exported to MPC's 
system but is not eligible for compensation for the capacity (kilowatts) of 
the plant committed to MPC during the contract life. Under the long term 
power purchase contract agreement, the seller commits the electrical output 
of the plant for period of at least four years. In addition to the payment 
for energy, the seller is entitled to payment for the net plant capacity 
committed to MPC during the contract life. 

Under the LTPP contract agreement, the seller commits the electrical output 
of the plant for at least four years. In addition to the payment for 
energy, the seller is entitled to payment for the net plant capacity 
committed to MPC during the contract life. 


Both of these payment schedules will be reviewed annually and are subject 
to revision by MPC with the Public Service Commission's approval whenever 
there is a change in the avoided costs to the utility for producing or 
purchasing energy for its customer. Consequently, the rates paid to the 
cogenerator may go up or down depending on the utility's avoided costs. 

MPC will offer a third type of tariff schedule called the Levelized Payment 
Option in the near future. This option will allow the cogenerator to 
contract with MPC for a known and fixed levelized rate, which would remain 
in effect for the life of the contract. 

The proposed specifics of the levelized payment option has not been 
announced, but other utilities have determined the fixed rate by predicting 
the escalation in the avoided cost over the proposed contract life and to 
discounting the future rates in order to obtain an "equivalent" annual 
fixed rate. This would permit the cogenerator to receive a rate higher 
than avoided costs in the early years of the contract and a lower rate in 
the latter years, which has the distinct advantage of giving the owner a 
higher return on investment for the cogeneration plant during the initial 
years of the contract. 


Public Service Commission of Montana 

The Hont.ana ..P.ov.ex.. Company. 

Niu of Company) 

Sheet NO...STP.P-82 Supp. ill 

Candling Sha.t No.STPP-82 

Page 1 of 2 

ScKedu»«uSIP.P^a2...Supp. ill 

Short-Term P ower Purch ase 

— Service 

AVAILABILITY : To any Seller who operates facilities for the purpose of 

generating short-term electric energy in parallel with the Compa- 
ny's system. This schedule is applicable to Cogeneration and 
Small Power Production (COG/SPP) facilities that are Qualifying 
Facilities under the Rules of the MPSC. 

DEFINITICNS: "Seller," for purposes of this schedule, is any individual, 
partnership, corporation, association, government agency, 
political subdivision, municipality, or other entity that: 

1. Operates a qualifying COG/SPP facility; 

2. Has signed the standard written contract with the Company 
stipulating the terms and conditions of the interconnection 
and sale of electricity to the Company; 

3. Has agreed in the standard contract to provide electricity 
to the Company on a short-term basis as defined in the 

"Company" means The Montana Power Company. 

"MPSC" means The Montana Public Service Commission. 

"Contract Year" means twelve months beginning on July 1. 

RATE : $0.0234/kWh 


1. Change of Rate : This schedule will be reviewed annually for each 
Contract Year and revised upon MPSC approval. 

2. Net Billing Option : If the Seller opts for Short-Term Net 
Billing in the standard contract and the Seller's consumption kWh 
exceeds the production kWh, the Seller will be billed for only 
the consumption kWh in excess of production kWh according bo the 
Company's applicable Retail Sales Rate Schedule. If the Seller's 
consumption kWh is less than the production kWh, the Seller will 
receive payment for only the production kWh in excess of consump- 
tion kWh according to the energy rate in this schedule. A Seller 
under this Option will receive no separate payment for capacity, 
and all metered consumption kW (if applicable) will be billed to 

(Signature of Officer of Utility) 

(Spice for Stamp or 
Seal of Comnuiiioo) 


Eff«tlT« - 



•Space below thcae linea for nae of CotnmUaloo on It. 


Public Service Commission of Montana 

The.-Montana>: Sheet No STPP-82 Supp. 

_ _. Candling Sh«l No... STPP-82 

Name of Company) Page 2 of 2 


STPP-82 Supp. #1 


Power Purchase 

- Service 

the Seller according to the Company's applicable Retail Sales 
Rate Schedule. If the Seller is demand-metered for consumption, 
the Seller will be required to install a kW/kWh meter to 
separately measure production. 

All service provided by the Company under this and all other 
schedules is governed by the rules and regulations approved by 
the MPSC. 


lamed.— (Date) ^ {Signature of Officer of Utility) 

Appro»ed "(D»l7) E ^ (Date) 

(Space lor Stamp or gg 

Seal of Comminion) _ - 

'Space below OSeae linea lor hk of Com mi a*] on only. Secretary. 

Public Service Commission of Montana 

The Montana ..Power.. Company. _. SKeei No...LTPP.-82 Supp 

_ Cndllng Shaet No.LTPP-82 

Nam* of Company) Page 1 of 3 

ScUJule-LTP£- 8 -?.-SyPP- #1 

Long-Term Power Purchase-- _ ._ 3c 


AVAILABTT.TTY : lb any Seller who operates facilities for the purpose of 
generating long-term electric energy in parallel with the Ccnpa 
ny's system. This schedule is applicable to Cogeneration and 
Small Power Production (OOG/SPP) facilities that are Qualifying 
Facilities under the Rules of the MP SC. 

DEFINITIONS : "Seller," for purposes of this schedule, is any individual, 
partnership, corporation, association, government agency, 
political subdivision, municipality, or other entity that: 

1. Operates a qualifying COG/SPP facility; 

2. Has signed the standard written contract with the Company 
stipulating the terms and conditions of the interconnection 
and sale of electricity to the Company; 

3. Has agreed in the standa r d contract to provide electricity 
to the Company on a long-term basis as defined in the 

"Company" means The Montana Power Company. 

"MPSC" means The Montana Public Service Commission. 

"Contract Year" means twelve months beginning on July 1. 

RATE : Energy: $0.0533/kWh 

Capacity: The Seller will be compensated monthly for capacity accord- 
ing to the following formula: 

$ /Annual Contract kW/month = ^'"^ oc^*"*""^ 

. o_> 

where: ACCF = Annual Contract Capacity Factor 

Annual Capacity Payment Adjustment: At the end of each Contract Year, 
a reconciliation of the accumulated monthly capacity payments made to 
the Seller for the Contract Year and actual capacity value to the 
Company for the Contract Year will be made utilizing the following 

l" gC d " " (Pitt) ^_ (Signature of Officer of Utility) 

Approved Effective — _ _ — _ 

(Date) (Date) 


(Space lor Stamp or 69 

Seal of Commiaaion) _ _. 

'Space below 0>eae linei for n»e of Commiaaion only. Secretary. 

Public Service Commission of Montana 

The. .Montana .Power. Company _. Sheet No . LTPP-82 Su 

_ :• Candling Sheet No.LTPP-82 

Nam* of Company) _ 

— p age 2 of 3 

ScWuU_Lm-J.2._£ypp. n 

Long-Ter m Pow er P urchase 


$/AAKW - (80.92 x ACCF) (AACF) (AAKW) 
( .85 ) (ACCF) X (ACKW) 

Refund to Company = (Dollars Paid to Seller) - ($/AAKW) (AAKW) 

Where AAKW = Annual Actual kW (for Contract Year) 
ACCF = Annual Contract Capacity Factor 

AACF = Annual Actual Capacity Factor (for Contract Year) 
ACKW = Annual Contract kW 

If AAKW is greater than ACKW then AAKW = ACKW 

1. Change of Rate : This schedule will be reviewed annually for each 
Contract Year and revised upon MPSC approval. 

2 - Net Billing Option : (A) If the Seller opts for Long-Term Net 
Billing in the standard contract and the Seller's consumption kWh 
exceeds the production kWh, the Seller will be billed for only 
the consumption kWh in excess of production kWh according to the 
Company's applicable Retail Sales Rate Schedule. If the Seller's 
consumption kWh is less than the production kWh, the Seller will 
receive payment for only the production kWh in excess of consump- 
tion kWh according to the energy rate in this schedule. 

(B) To meet the conditions of this Option and to receive a 
separate capacity payment, the Seller's consumption must be 
measured and billed on a demand basis and a separate kW/kWh meter 
to measure production is required. Under this Option, the Seller 
will be billed at the Company's applicable Retail Sales Rate 
Schedule for only the consumption kW in excess of the production 
kW. If the Seller's production kW exceeds the consumption kW, 
the Seller will be compensated for only the production kW in 
excess of the consumption kW according to the Production Capacity 
Payment Procedure detailed in this Schedule. The calculation of 
monthly capacity payments for the expected excess production kW 
will utilize the expected annual net production capacity factor. 
The Annual Capacity Payment Adjustment is to be applied to the 
actual excess production kW for the Contract Year. The procedure 
will utilize the annual contracted and annual gross production kW 
and gross capacity factor information for payment reconciliation. 

Itioed _ By_ 

* ( Plt *) (Signature of Officer of Utility) 

Appro»ed._._ Effectire _ 

(Date) (Date) 

Seal of Commiiiion) 

•Scvact: below theae linea for o»e oi Coromiaaion on It. c^. rr , hr> 

Public Service Commission of Montana 

The MonLana Power.. Company Sheet No LTPP-82 Su 

Cnclllng SS..I No. LTPP-82 

Nann of Cotnpiav) Page 3 of 

Long-Term Power Purchase o 

■ - - - *^Cf VI 


3. All service provided by the Conpany under this and all other 
schedules is governed by the rules and regulations approved by 
the MPSC. 


• (Ditc) 7 (Slyruture of Officer of Utility) 

Approved Effective _._ _ 

(Date) (Date) 


(bp»ce tor bump of 

Seal of Commiiiion) 

• Sp»ce b-elow thcx line* for n*e oi CommU-iion oory. f - ™ 


A sample contract for power purchase agreement between the Cogenerator or 
Small Power Producer and the MPC is included in Section C of the "Guide- 
lines for the Interfacing of Cogenerators and Small Power Producers with 
the Montana Power Company System." The contract as proposed by MPC 
stresses the protection of the buyer (utility) and to a lesser extent the 
Seller. The contract in the Appendix of this report should be a good 
starting point for developing a workable contract agreement between both 



The investment required for a complete power plant facility is a major 
undertaking for most industrial users. For that reason, it is imperative 
that the owner have at his disposal a thorough economic analysis of the 
proposed investment. With that end in mind, this section provides a 
comprehensive economic analysis for the 3 MW biomass fired cogeneration 
plant at the Flodin Lumber sawmill. 

Estimated power plant costs are examined before the results of the 
ecomomic analysis are discussed. 


The costs of the biomass fired cogeneration plant can be divided into the 
following categories: 

Capital Costs 

Fixed Operating Costs 

Variable Operating Costs 

5.1.1 Capital Costs 

Capital costs of the proposed power plant, as described in Section 3.0, 
are delineated in Table 5-2. The capital costs include equipment, 
material, installation, engineering and design, and other costs necessary 
to furnish a complete operating facility. 


TABLE 5 - 1 


(1983 Dollars) 

Steam Generator $1,000,000 

Turbine Generator (Including refurbishing) 350,000 

Fuel Handling System 506,000 

Balance of Plant (Mechanical) 

Surface Condenser (Refurbishing Cost Only) 10,000 

Cooling Tower (Including Erection) 60,000 

Demineral izer 104,500 

Deaerator 11,500 

Boiler Feed Pumps 22,300 

Condensate Pumps 12,800 

Circulating Water Pumps 19,700 

Condensate Makeup Pump 1,000 

Condensate Storage Tank 20,000 

Boiler Blowdown Tank 3,000 

Air Compressor & Dryer 7,200 

Ash Handling 50,000 

Piping, Valves, Insulation 100,000 

SUBTOTAL 422,000 

Electrical Equipment 

Generator Breaker and Auxiliaries 67,300 

Generator Metering and Relay Panel 70,000 

Step-up Transformer 38,700 

Auxiliary Transformer 9,800 

MCC & Main Breaker 20,000 

High Yard Breaker 43,600 

Installation Materials 60,000 

SUBTOTAL 309,400 


Based on current estimates from manufacturers 


TABLE 5 - 2 


Equipment Costs 

Steam Generator 1 , 000 , 000 

Turbine Generator 350,000 

Fuel Handling 506,000 

Balance of Plant (Mechanical) 422,000 

Balance of Plant (Electrical) 309,400 

SUBTOTAL 2,587,400 

Installation Costs 

Steam Generator Erection 300,000 

Turbine-Generator Installation 100,000 

Fuel Handling Installation 200,000 

Civil and Structural 371,000 

Mechanical Installation 119,000 

Electrical Installation 40,000 

SUBTOTAL 1,130,000 

Engineering and Design 250,000 

Contingencies (5%) 198,400 

TOTAL $4,165,800 


The equipment costs, summarized in Table 5-1, are based on current 
estimates from manufacturers. All the equipment prices, except the steam 
turbine generator and condenser, are based on 1983 dollars for new 
equipment. The turbine generator and condenser costs include the purchase 
price of used equipment, removal of equipment from its present sites, 
transportation and refurbishment. 

The itemized list of construction or erection costs are based either on a 
1983 composite labor rate of $16.50, or the erection cost as quoted by the 
equipment manufacturer. The individual installation cost items represent 
not only the field direct costs, but also the proportional share of field 
indirect cost, construction management, field adders and profit. 

The engineering and design costs are estimated at approximately 6 percent 
of the total plant cost, or $250,000. This will include complete design 
services to allow the project to progress from the conceptual phase all 
the way through final design and construction. A 5 percent contingency 
fund has been added to the total to account for miscellaneous items not 
included in this cost breakdown. 

The plant would be installed on the site of the existing sawmill, so the 
cost of land is not included in the capital cost total. 

5.1.2 Fixed Operating Cost 

The fixed operating costs comprise operating labor, maintenance labor and 
material, and overhead charges, which are essentially independent of the 
plant capacity factor. 

It is assumed that the personnel now operating the boiler plant would also 
operate the cogeneration plant. The operating personnel would then 
consist of one operator per shift and one swing, with no staff required 
above present levels. 


Maintenance labor will be provided by the maintenance personnel already 
working at the Flodin Lumber Sawmill. Therefore, the cost of maintenance 
labor for the cogeneration facility is not considered. 

The maintenance or replacement material costs associated with the new 
plant are estimated to be $60,000 per year in 1983 dollars or roughly 
1.5 percent of the total capital cost. 

Other fixed costs related to ownership of the plant are property taxes and 
insurance. The annual insurance premium is estimated at approximately 
$22,000 based on the current rate of $0.53 per $100 insured value that 
Flodin Lumber is paying for the sawmill. The annual property tax assessed 
to the cogeneration plant is assumed to be 1 percent of the initial plant 
cost, or $41,600. 

5.1.3 Variable Operating Cost 

Variable operating costs depend on or vary with the amount of power 
produced by the plant. These costs include fuel, water, chemicals, waste 
disposal, etc. 

Water will be supplied from the Clark Fork River, so no cost has been 
assigned. The pumping costs are included in the inhouse power 
consumption, which is subtracted from the gross electrical power to yield 
net salable power. 

The cost of chemicals for the demineral izer, boiler chemical injection 
system and other plant uses is estimated to be $8,500 per year at full 
load operation in 1983 dollars. 

The cost of waste disposal is not considered, because waste is disposed of 


5.1.4 Fuel Cost 

As described in Section 2.0, the fuel for the steam generator is wood shavings, 
sawdust and hogged fuel. Even though most of the fuel is generated by the 
sawmill operation, some supplementary wood shavings would be purchased from 
other sawmill companies. In addition to the cost of purchased fuel, Flodin 
Lumber has assigned a unit cost to the wood byproducts from the sawmill to 
properly account for theintrinsic value of the wood shavings and the the cost 
of processing hogged fuel. The prices assumed for the fuel on a unit basis 
(i.e. one unit equals 2400 lbs.) are: 

Hogged Fuel - $2.50 per unit 

Shavings - $5.00 per unit 

Sawdust - $2.50 per unit 

For the initial year of operation, the total fuel cost for 8000/hr per 
year operation is tabulated below: 

Shavings : 
Hogged Fuel : 
Purchased Shavings: 

1239 lb/hr x 8000 hr. x $5.00/2400 lb= $20,650 

1900 lb/hr x 8000 hr. x $2.50/2400 lb= $15,833 

8064 lb/hr x 8000 hr. x $2.50/2400 lb= $67,200 

2111 lb/hr x 8000 hr. x $5.00/2400 lb= $35,183 


For purposes of this study, the initial fuel cost is rounded up to $140,000 per 



The economic feasibility of the wood fired cogeneration plant investment 
is first considered as a "stand alone" project with no credit given for 
the replacement of the existing antiquated boilers and for the supply of 
steam to the kilns. The analysis then considers certain credits and 
adjustments to account for the above factors, thereby arriving at a more 
realistic comparison of the proposed investment. 


As discussed in Section 4.3, the sale of electricity to MPC is governed by 
one of two rate schedules. Schedule LTPP-82 Supp. # 1, which is for 
long-term power purchase, gives the more favorable terms to Flodin Lumber 
for electrical sales. 

Under this schedule, MPC would pay $0.0533 for each kilowatt hour 
generated by the qualifying cogeneration facility. Additionally, Flodin 
Lumber would be compensated for capacity of the facility contracted to 
MPC under the sel 1 /purchase agreement. The monthly capacity payment is 
determined from the following formula: 

$/Annual Contract KW/Month = $6.74 x ACCF 


Where ACCF = Annual Contract Capacity Factor 


Based on an annual generation of 24 million kilowatt hours (see Section 
3.8), the first year annual electrical sales for energy is $1,279,200. 
The annual capacity payment is calculated as follows: 

$/Annual Contract KW/Month = $6.74 x 0. 908/0. 85=$7.20/KW 
Monthly Capacity Payment = 3000 x 7.20 = $21,600 
Yearly Capacity Payment = 12 x 21,600 = $259,200 

The total annual revenues for both energy and capacity payments are 
$1,538,400. Dividing this annual revenue by the annual generation yields 
a composite electrical rate (i.e. energy and capacity) of $0.0641/KWH. 
Assuming annual electrical generation is constant for each year of 
production, the revenues are escalated at an annual rate of 6 percent. 



Operating Expenses 

This category covers all the business and plant operating expenses which 
reduce the tax liability indebted for the gross revenues from the sale of 

In addition to the fixed and variable operating expenses discussed 
earlier, the interest required to service the debt and the depreciation of 
the plant equipment are legitimate tax deductions. 

For purposes of this study, 100 percent of the plant capital cost is 
assumed to be financed through a conventional bank loan at 12 percent 
annual interest rate for a term of 15 years. The annual interest expense 
declines each year as the loan principal is payed off. 

As stated in Section 4.2 Tax Incentives, the proposed facility qualifies 
for an accelerated depreciation. This depreciation writeoff is 15, 22, 
21, 21 and 21 percent of the equipment costs in the first five years. 
Thereafter, no depreciation for tax purposes is allowed. The analysis 
considers future inflation, therefore, the fixed and variable operating 
expenses are assumed to escalate at an annual rate of 6 percent over the 
15-year plant life. 

Net Income After Taxes 

The after tax net income is defined as: 

After-Tax Income = (Revenue - Expenses) (1 - Tax Rate) 

The Federal Tax Rate assigned by the IRS for corporate income is 
46 percent. 

Debt Service 

This category covers the yearly mortgage payment, principal payment and 
remaining principal balance for the long term financing of the project. 


The monthly mortgage payment is calculated by multiplying the amount 
financed by the Capital Recovery Factor (CRF) 

Monthly Payment = Loan Amount x CRF 
Where CRF = i (1 + i)n 

(1 + i)n - 1 

For 12 percent APR and 15 years (180 months) financing, CRF = 0.012002 
Cash Flow 

Annual net cash flow after taxes as used in this analysis is defined as 
the sum of net income, book depreciation and deferrd taxes (if any). For 
this report, no distinction is made between book and tax depreciation, 
so, the depreciation used is the same depreciation listed under operating 

After Tax, Discounted Return on Investment (ROI) 

Once the after-tax cash flow is obtained, the economic feasibility of the 
project can be examined. There are several methods in industry for 
determining the economic worth of a project: payback, net present worth, 
equivalent annual worth, and return on investment. This report will look 
at the after-tax return on investment. The payback method, which has 
traditionally been used as a benchmark for the economic viability. of an 
investment, does not account for the time value of money, the effect of 
inflation and escalation in annual fuel, electrical, and labor costs. 
Return on investment (ROI) more accurately evaluates the impact of rising 
fuel and electrical costs, labor costs and other costs affected by 
inflation. The ROI is defined as the annual interest rate which equates 
the sum of the present value of the net cash flow and the installed 
equipment cost to zero or, in other words, the interest rate which makes 
the sum of the present value of the net cash flow equal to the capital 



-CI + 3>PWFj X ARj 

PWFj = 

(1 + i)J 


Where CI 

Capital Investment (negative cash flow in first year) 


Single payment present work factor which discounts the 
future net cash flow to its present value. 


Net after-tax cash flow 

Interest rate on return on investment. 

For purposes of this study, the capital investment used in computing the 
ROI for each alternate is the capital required after deducting the 
appropriate investment tax credits. 

Sensitivity Analysis 

From Table 5-3 it can be seen that the cogeneration plant generates an 
attractive after-tax cost flow throughout the project life. The discounted 
return on investment for the complete biomass fired cogeneration plant 
based on this cash flow is 26 percent. Typically, a ROI of 12 to 
15 percent is considered as the minimum acceptable rate of return for 
cogeneration type projects. 

Since the return on investment for a particular project is dependent on 
the capital cost and the revenue generated by the project, a sensitivity 
analysis has been performed to evaluate the sensitivity of the ROI to 
changes in the capital cost and sale of electricity. 

Figure 5-1 graphically illustrates the impact on the ROI with changes in 
the composite electrical rate for the sale of electricity to MPC. If MPC 
is successful in having the Public Service Commission reduce the avoided 
cost from $0.0641 to $0.04/KWH, the ROI would drop from 26 percent down to 
13 percent. Even based on this worst case scenario, the project is still 
economically feasible. 


A A 


s § 

8 § 

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1 I 

b a 

I I 

s s 

1 § 

S 3 

2 I 

S a 

2 -2 

s s 

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8 8 

2 2 

! ! 

3 3 

i i 

5 5 
I § 

3 S 









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SI : § 









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| 22,000 
11 ,600 






! !L ! S. i ,9 



iff! I 1 



ROI 28 ■ 



The effect of varying the initial capital investment on the ROI is 
depicted in Figure 5-2. As can be expected, the ROI increases as the 
capital cost is decreased. Assuming a band of _+ 25 percent on the capital 
cost estimate of $4,166,000, the ROI would range from 21 percent to 
34 percent. 

Generating Costs 

The generating costs associated with the generation and sale of electrical 
power over a 15-year operating period are given in Table 5-4. 






Generating Costs (miHs/Kwh) 
Year & M Fuel Insurance Taxes Total 





11 A 






12. 1 











5 . 

























































The following financing alternatives have been examined sources of funds 
for construction of the plant: 

1. Economic Development Administration 

2. Rural Electrification Administration 

3. Department of Natural Resources 

4. Conventional Bank Financing 

5. Industrial Revenue Bonds 

There are other options which can be pursued such as leasing or third 
party ownership and limited partnerships, but these are beyond the scope 
of this report. 

Economic Development Administration - Grants 

According to the chief of the Business Loan Division of the EDA, grants 
are given only to municipalities and cities whereas grants to private 
parties, individuals or companies are illegal. Consequently, with private 
ownership of the cogenerat ion , Flodin Lumber would not be entitled to 
receive a grant from the Economic Development Administration. 

Rural Electrification Administration - Funding 

The Rural Electrification Administration makes loans to utilities in rural 
areas. In order to obtain a REA guaranteed loan commitment, an electric 
cooperative would have to have ownership of the power plant. 

Department of Natural Resources - Grants and Loans 

The Montana Department of Natural Resources and Conservation (DNRC) has 
established a Renewable Energy Program to reduce the state's reliance on 
fossil fuels through the increased use of alternate fuels such as biomass. 
This program funded through Montana's Coal Severance Tax offers grants or 
loans to encourage the private sector's involvement in renewable energy. 


The grant program is restricted to research, development and demonstration 
projects, whereas the loan program encompasses commercial ventures and 
projects which have an income generating potential. 

For fiscal year 1983, the maximum loan amount available to a single 
borrower is limited to $202,500 with repayment to be made within 10 years. 
This program does apply to facilities which sell electricity to the 
utility grid under the Public Utilities Regulatory Policy Act. 

Conventional Bank Loans 

The project cost could be financed through a conventional bank loan. 
Given that the loan would be borrowing against the value of the plant and 
the credit of the owner, the banking institution would most likely be 
interested in the following information: 

1) Credit history of the borrower 

2) A projected income and cash flow statement showing the profits 
and cash flow produced by project. 

3) The power purchase agreement or contract between the cogenerator 
and the utility. 

4) Fuel supply contract (if any). 

5) The ability of the project to service the debt in the event of a 
cutback in the sawmill operation due to a recession or downturn 
in the lumber industry. 


Upon analyzing this data, the bank would assess the credit worthiness of 
the owner, the economic feasibility of the project and risks associated 
with the project. As a portion of the bank's business is making loans, 
a bank probably would be willing to finance the project if it were 
satisfied with the items. Interest rates for conventional bank loans for 
industrial projects of this magnitude average about 12 percent. 

Industrial Revenue Bonds 

Repayment of the bonds would be strictly from the revenues generated by 
the project. Therefore, the bonds would be secured only by the project 
revenues and the credit of the owner. The bonds can be issued for periods 
of up to 30 years, but shorter terms are normally preferred to improve 
acceptance in the bond market. 

At present, tax exempt bonds can be issued at an interest rate of 
approximately 8.0 percent. Several type of bonds which are issued under 
the auspices of state and local governments are: 

— Pollution control revenue bonds, available to finance the 
installation of equipment designed to control or abate pollution. 
There is no ceiling on the amount of bonds that may be issued for 
this purpose. 

--County Government can issue power option bonds to finance 
construction of electric generating plants. The power must be sold 
within the county area where it is generated to qualify for 
financing by this method. 


-Solid waste disposal bonds may be issued to finance solid waste 
disposal facilities. The Federal IRS has said that waste material 
which has value or will obtain a value is not eligible for tax 
exemption. The IRS does not consider wood residue a solid waste 
disposal problem. Thus, this financing option is available only if 
refuse derived fuel (RDF) is burned in the furnace, and may not be 
available if the RDF is considered to have a value. 

-Economic development revenue bonds are issued for the purpose of 
expanding the economy through the creation of jobs and increasing 
the property tax base. The facility must be located in an 
economically lagging area. Usually, state law prohibits use of 
revenue bonds for any facility designed primarily for generation, 
transmission, sale, or distribution of electrical energy. There- 
fore, financing of the turbine generator by this method would not 
be permitted. 




The proposed biomass fired cogeneration facility will be located in 
Sanders County (Section 18, Township 49W, Range 28u), Montana, 
approximately 5 miles from Thompson Falls, on property owned by Flodin 
Lumber and Manufacturing Comapny. The new facility will be situated 
adjacent to the existing sawmill as shown on the Plot Plan, Drawing No. 

The climatic conditions for the site which would be considered in the 
design of the plant are tabulated below: 

Site Elevation above mean sea level 2500 ft. 

Maximum ambient air temperature 95°F 

Minimum ambient air temperature -16°F 

Design Summer Wet Bulb Temperature 65°F 

Relative Humidity Range 40-100% 
Annual Rainfall 

Earthquake Zone (UBC) 2 

Design Wind Velocity 90 MPH 

Access to the site is from State Highway 200 running along the western 
property line. 

Water Source and Requirements 

Makeup water for the new facility will be obtained from the existing 
110,000 gallon raw water storage tank. The tank receives water pumped 
from the Clark Fork, which runs along the boundary of the property. The 
analysis of the river water is given in Table 6-1. 

The maximum requirements for makeup water to the plant is approximatley 
122 GPM as shown on the Water Balance, Drawing No. 40X3011F-M204. 
Essentially, makeup is required only for the thermal cycle and cooling 
water cycle. Makeup to the thermal cycle is required for cycle losses 
incurred from boiler blowdown and unrecovered condensate from the kilns. 


TABLE 6-1 




Rivpr Water 




7 .95 

Ph o nf\l nh ~t" h a 1 oin Al If a! i m' 
rilCilUipilCilalCliI Ml Ka 1 III! vy 

a^ PaTHo nnm 

1 U La 1 nl Ka 1 1 II t iy 

ac r^POo nnm 


ny urate mi Ka 1 1 n l xy 

ac PaPOo nnm 

union ut? 

ac Pi nnm 

ad wi ^ p pm 


OU I i ate 

ac *\C\a nnm 

a> JUA j Pr 


1 i 1 La a!) 

Slflo nnm 


i u ua i nai uncbo 

ac. CaPOo nnm 


Calcium Hardness 

\SVtlV>IUIII 1 1 Ul 1 Ml IV. J J 

as CaCOi dditi 

UiJ W \y \J < y LS yj 1 II 


Maanesium Hardness 

1 IUHI IV J I Villi 1 1 vl 1 VAI 1 V. J J 

as CaCO^ dditi 

WW VSU\SV/ A • wwlll 


JU 1 1 1 LC 

ac 90o nnm 

To, t* a 1 Phncnha +*o 

ac P()a nnm 

ur tnupnuspna tc 

AC POa nnm 
a> ruA) ppiii 


ac Pp nnm 
go r c j p pin 

optrC 1 1 1 L LUnUUClailLc 

Mi cromho^ 


Specific Conductance 

Micromhos (corrected) 


Colorless and 


*Sample Taken by Garratt-Callahan Company on October 13, 1976. 


The makeup to the cooling tower of 94 GPM is to compensate for losses in 
the closed cooling water system due to evaporation, drift and blowdown. A 
makeup demineral izer is utilized to obtain suitable boiler quality water. 


Since a soils analysis of the site was not available, only tentative 
conclusions can be drawn. From visual inspection, the site is relatively 
level and devoid of obstruction. According to the owners, the sawmill and 
surrounding area rests on a gravel base approximately fifty feet deep. 

From this limited information, pilings are probably not required for 
equipment and building foundations. For the purposes of this study, 
spread footings are the only deep foundation type required. 


6.2.1 Quality Control 

At present, the Sanders County area is classified by the Environmental 
Protection Agency (EPA) as a Class II region. The applicable emission 
standards for this region as stated in the Quality Rules of the Montana 
Department of Health and Environmental Sciences, Environmental Management 
Commission (Title 16, Chapter 8, Subchapter 14 of the Administrative Rules 
of Montana) are outlined below: 

For particulate emission, 




Heat Input In 
Million BTU/Hour 

Maximum Allowable Emission 

of Particulate Matter in 

Lbs/Million BTU 

up to and including 10 






For a heat input between two consecutive heat inputs stated in the 
preceding table, maximum allowable particulate atter shall be calculated 
by the equation below: 

E + 1.0 X q-0.2230 

Where Q - heat input of fuel burning equipment in million 

E - Maximum allowable emission of fly ash and/or 
other particulate matter in lb per million BTU 
heat input. 

Sulfur Dioxide emissions caused by the combustion of fuel or fuels to be 
discharged from any stack or chimney shall not exceed one lb. of sulfur 
per million BTU input. 

Since there is an insignificant amount of sulfur dioxide emissions brought 
about by the combustion of wood/wood waste fuels, there is no need for a 
flue gas desulf uri zation system to limit the SO2 emissions as would be 
the case with burning "noncompliance" high sulfur coal or even high sulfur 
fuel oil. 

To keep the particulate emissions within the stated limits for the 
proposed boiler, a high efficiency mechanical collector should be 

New wood fired boiler installations must also conform to the Prevention of 
Serious Deterioration (PSD) of air quality, 40 CRF 52 Protection of 
Environment, if the boiler firing rate exceeds 250 million BTU/Hr or the 
total of any type pollutant (i.e., particulate, N0 X , SO emitted 
during a year exceeds 250 tons. 

An installation which falls into this category is termed a "major 
stationary source" or "affected facility" and is also subject to the more 
stringent New Source Performance Standards promulgated in 40 CFR 60. 


The boiler firing rate at full load is appropriately 70 million BTU/HR. 
Therefore, the maximum allowable particulate emission is calculated below 

E = 1.0 x (70)" - 2230 = 0.388 lb/MMBTU 

Assuming worst case situation (full load operation for 8000 hr/year). 

Annual Particulate Stack Emission = 70 MMBTU/HR x 0.388 lb/MMBTU 

x 8000 hr/year 

= 217,280 lbs or 109 tons/year 

Based on the worst case scenario, the new boiler would not be classified as 
a "major stationary source," so would not be subject to New Source 
Performance Standards. 

6.2.2 Water Quality/Usage 

As previously discussed, the cogeneration facility, as envisioned, would 
use a closed cooling water system and a condensate return system. Water 
usage and discharge, therefore, would be small. In the way of water 
usages, a single intake or supply point is required for cycle make-up and 
cooling tower make-up. 

Very little effluent would be discharged from the facility and this would 
consist of "disposable" quality water without undesirable chemical 
contaminates. Waste water will be produced from: 

"Cooling Tower Blowdown 
"Boiler Blowdown 

'Water Treatment Regeneration Water (depending on water treatment 
required) . 


In all cases, water will be suitable (or made suitable by means of simple 
treatment) to allow disposal locally. The requirements of the Montana 
Department of Health and Environmental Sciences have been investigated and 
do not appear to pose any restrictions or requirements that cannot be met with 
conventional or normal treatment of the plant effluent. 

The Clark Fork adjacent to the site is designated by the Montana Department of 
Health and Environmental Sciences as having a water quality classification of 
B-l. As such, it is subject to the Water Quality Standards given in the 
Administrative Rules of Montana entitled "Surface Water Quality Standards," 
Title 16, Chapter 20, paragraph 16.20.618. The specific requirements which 
pertain to the discharge of blowdown from the facility are water temperature and 
pH as stated below. 

A 1°F maximum increase above naturally occurring water 
temperature is allowed within the range of 32" F to 66° F; 
within the naturally occurring range of 66° F to 66.5° F, no 
discharge is allowed which will cause the water temperature to 
exceed 67° F; and where the naturally occurring water 
temperature is 66.5° F or greater, the maximum allowable 
increase in water temperature is 66.5° F or greater, the 
maximum allowable increase in water temperature is 0.5°F. 

Induced variation of hydrogen concentration (pH) within the range 
of 6.5 to 8.5 must be less than 0.5 pH unit. Natural pH outside 
this range must be maintained without change. Natural pH above 
7.0 must be maintained above 7.0. 

Discharge of waste water to the Clark Fork will be monitored to assure 
conformance to the standards. 

6.2.3 Noise 

Contribution of additional noise by the cogeneration plant would not 
violate noise standards. Judicious design of the plant can ensure 
compliance with 0SHA standards for protection of operating personnel from 
noise exposure. 


6.2.4 Solid Waste Management 


Ash generated from burning sawmill wood waste in the existing power boilers 
and teepee burners is disposed of onsite at the company owned landfill. 

This method would continue to be used after the cogeneration plant begins 



The schedule for building a biomass fired cogeneration plant of the type 
described herein is estimated at 24 months. The schedule can be divided 
into four broad phases. 

"Environmental Review and Permitting - 6-10 months 
"Conceptual Engineering and Equipment Procurement - 4-6 months 
"Detailed Engineering/Design and Equipment Delivery - 12 months 
"Construction Including Erection and Startup - 12 months 

A further breakdown of the major project activities are depicted in a bar 
chart graph in figure 6-1. Equipment deliveries currently quoted by 
manufacturers are 12 months on the boiler and 14-16 months on the turbine 
generator after placement of the purchase order. A used turbine-generator 
will be purchased instead, so the cycle time for removal, transportation 
and refurbishment would not exceed 12 months. 

The total project duration of 24 months is readily achievable based on the 
following premises: 

° Purchase orders be placed as soon as possible on long delivery 
equipment such as the boiler and turbine-generator. 

* Engineering and design and equipment procurement be performed in 
parallel with the environmental review and permitting phase of the 

If no commitments can be made on major equipment until after the permitting 
process is complete, a total schedule exceeding 30 months can be expected. 


"I no 


Prior to the construction and/or operation of an industrial facility in 
Montana, certain permits are required by federal, state or local regulatory 
agencies. Jurisdiction of Federal Air and Water Quality Standards in 
Montana has transferred from the U.S. Environmental Protection Agency to 
the State of Montana, so application for the following permits would be 
processed, reviewed and approved at the state level. 

-Montana Pollutant Discharge Elimination System (MPDES) Permit 
-Air Quality Permit 

The MPDES permit is required of any owner or operator of any proposed point 
source discharging pollutants into state waters. A completed MPDES permit 
application must be filed with the state no less than 180 days prior to 
operation of the point source. The specific requirements for application 
are delineated in Paragraph 16.20.904 of the Administrative Rules of 
Montana on Water Quality. 

An Air Quality Permit is required prior to construction, installation, 
alteration or use of any air contaminent source or stack associated with 
any source, unless specifically excluded in Paragraph 16.8.1102. The 
submittal of the air quality permit application differs from the 
aforementioned in that the application must be made 180 days before 
construction begins. The permit application requirements are specified in 
the Montana Air Quality Standards, Paragraph 16.8.1102. 

In most localities, a building construction permit will not be issued until 
the necessary environmental permits have been applied for and issued by the 



7 . 1 Conclusions 

The addition of a biomass fired cogeneration plant at the Flodin 
Lumber and Manufacturing Company's sawmill facility is a feasible and 
economically attractive investment. The supply of wood byproducts 
from the Flodin Lumber sawmill operation and neighboring sawmills is 
readily available, inexpensive, and sufficient to support the 
operation of a 3 1/2 MW cogeneration plant. 

The design of the complete cogeneration facility for the burning of 
wood in a power boiler and the subsequent generation of electricity 
is a well established and proven technology. The environmental 
constraints placed on new wood fired boilers installations by Federal 
and State regulatory authorities are readily achieved by best 
available control technology without undue expense to the owner. 

Legislation enacted by Congress provides numerous incentives at the 
federal and state level to encourage the companies such as Flodin 
Lumber to undertake cogeneration projects which typically are highly 
capital intensive. One such incentive is the investment and energy 
tax credits granted to qualifying companies to help offset part of 
the initial capital expenditure. Other legislative incentives ensure 
that the cogenerator can interconnect with the Utility's grid and 
sell the electricity generated to the Utility at a fair and just 

At present, MPC, under mandate of the Montana Public Service 
Commission, is required to purchase electricity from qualifying 
cogenerators at 100 percent of the full avoided cost. Based on the 
long term power purchase schedule currently in effect, the discounted 
return on investment based on the after-tax cash flow generated from 
the sale of electricity is 26 percent. This high rate of return may 
be reduced if either the final capital costs exceed the budgetary 


estimate or the utility is successful in its appeal to the Public 
Service Commission to have the rates for power purchase decreased. 
The sensitivity analysis performed herein shows that the ROI for the 
cogeneration plant would still be an attractive investment for Flodin 

Flodin Lumber's alternative to cogeneration is to continue to operate 
the existing 40-year-old boilers until such time as they need to be 
replaced with a 125# wood fired packaged boiler. Since replacement 
of the boilers is inevitable, the addition of a complete cogeneration 
plant in lieu of a new package boiler would be advantageous, consid- 
ering the favorable legislation and tax incentives available to 
cogenerators burning alternate biomass fuels. 

Reco mmendations 

Having received and reviewed the feasibility study content and find- 
ings, Flodin Lumber Company has stated concurrence with the recommen- 
dations set forth therein. By way of continuing the developmental 
phase of the biomass to energy program, Flodin has initiated the 
following project related activities: 

Initiated preliminary discussions with the State of Montana 
Environmental Regulatory Authorities with view to determining the 
nature and extent of applicable air, ground and water emission/ 
pollution control mandates attending the inception of the energy 
generating facility. 

Solicited from the General Electric Company, a firm price and firm 
schedule bid to engineer and construct the biomass to energy 
plant. Current plans call for the offering to be delivered for 
Flodin Lumber Company's review during November of 1983. 

Initiated dialogue with financial institutions with a view to 
properly determine the financing alternatives available to 


Flodin as Owner of the energy generating facility. Said option's 
include the "trading" of investment and energy tax credits in 
return for a power implicit interest rate, leveraged leasing, 
revenue bonding and general obligation bonds and such other inno- 
vations as are available to effectively finance the program. 

With the above in hand, Flodin Lumber Company will be able to make an 
intelligent decision relative to proceeding with the project. Cur- 
rent indications are that a decision will be forthcoming during the 
late '83/early 1984 timeframe. 




One method of decreasing the initial capital investment which has been used 
quite successfully is the purchase of used equipment. This equipment is 
usually available for 1/4 to 1/2 the price of new equipment. Although 
refurbishment and general tune-up is required in most instances, the net 
result is usually a significant capital cost savings. 

The most important aspect of used equipment purchase is the search and 
selection of the potential equipment and its "serviceability" assessment by 
knowledgeable craftsmen. If this function is performed correctly, the 
result is equipment that will perform the function intended for many years 
at significant cost savings. 

Many reputable dealers are available and willing to advise what type of 
equipment is available and will also provide a "history" on each piece. 
Equipment which may be successfully purchased in this manner includes: 

Steam Turbine/Generator and Auxiliaries 
Power Boiler and its Auxiliaries 

For the purpose of this study, only the steam turbine generator and 
associated auxiliaries are explored. The feasibility of utilizing a used 
power boiler is ordinarily limited to packaged units. In very few 
instances, used field erected boilers may be considered depending on such 
factors as the proximity of the existing boiler to the job site and the 
type of boiler construction (i.e. modular construction lends itself more to 
disassembly and relocation). 


Table 8-1 gives a listing and description of several used turbines which 
are presently available for purchase. The turbine generator which best 
fits the cycle requirements of the new facility is Item 2 on the list. 

NOTE : The installation impact of used equipment must be reviewed prior to 
purchase. For example, the installation cost of a used turbine should be 
the same as a new unit plus the removal of the used turbine cost. The 
installation costs of a field-erected boiler will be higher than that of a 
new unit, in addition, the removal costs will be quite high. 


TABLE 8-1 

1. 1 - 3000 KW 80 percent PF 3750 KVA General Electric generator, 3 phase, 60 cycle, 
13,200 volts, 3600 RPM, direct connect to 

1 - 3000 KW General Electric condensing turbine, 600# steam pressure, 800 F, 
3600 RPM. 

Turbine equipped with condenser. 


2. 1 - 3500 KW 80 percent PF 4375 KVA General Electric Generator, 3 phase, 
60 cycle, 2400 volts, 3600 RPM, direct connected to 

1 - 3500 KW General Electric condensing extraction turbine, 600# steam pressure, 
55# extraction, Form GG, 3600 RPM. 

New 1945. Rebuilt 1967. 

3 - 5000 KW 80 percent PF 6250 KVA General Electric generators, 3 phase, 
60 cycle, 11,500 volts, Type ATB-2, 3600 RPM, directed connected to 

3 - 5000 KW General Electric condensing double extraction turbines, 540# steam 
pressure, 700 F, with automatic extractions at 150# and 50#, Form JJ, 3600 

Generator equipped with exciters. 

Turbines equipped with Allis Chalmers surface condensers. 
New 1942. 

4. 1 - 5000 KW 80 percent PF 6250 KVA General Electric generator, Type ATB, 
3 phase, 60 cycle, 2400/5160 volts, 3600 RPM, direct connected to 

1 - 5000 KW General Electric condensing turbine, 400# steam pressure, 750 F, 
15 stage, 3600 RPM. 



5. 1 - 7500 KW 80% PF 9375 KVA General Electric generator, 3 phase, 60 cycle, 
13,200 volts, 3600 RPM, direct connected to 

1 - 7500 KW General Electric condensing turbine, 400# steam pressure, 750 F, 16 
stage, 3600 RPM. 

New 1950. 



1. Plant operation for sawmill is 16 hrs/day, 5 days/week, with 11 
holidays a year. The cogeneration plant is assumed to operate 8000 
hr/yr . 

2. The operating personnel for the new cogeneration plant will be the same 
as for the existing boiler plant, i.e. 4 operators, 1 per shift and one 
swi ng . 

3. The customer's minimum acceptable rate of return (MARR) is 10-12 percent. 

4. Plant life for the purposes of this study is assumed to be 15 years. 

5. Insurance premiums are 53$ per $100 of insured property. 

6. The current property tax rate is estimated at 1 percent of market 

7. Capital costs for the proposed plant are in 1983 dollars. 

8. Interest during construction is not considered in the economic 
analysis . 

9. Operating expenses and revenues from electrical sales is assumed to 
escalate at 6 percent annually. 

10. Financing for the project is assumed to be 100 percent of the capital 
cost at 12 percent APR for a term of 15 years. 

11. Fuel costs for wood byproducts from the sawmill operation are assumed 
as $2.50/unit of hogged fuel, $2.50/unit of sawdust and $5.00/unit of 
shavings . 

12. It is assumed the Flodin Lumber can take advantage of the available tax 
credits for the cogeneration plant investment to offset the tax 
liability on profit from the sawmill operation. 



Guidelines for the Interfacing of Co-Generators and Small Power 
Producers with the Montana Power Company System, May 1982. 

"In the Matter of Avoided Cost Based Rates for Public Utility Purchases 
from Qualifying Cogenerators and Small Power Producers," Dept. of 
Public Service Regulation Before the Public Service Commission of the 
State of Montana, Utility Division Docket No. 81,2,15, Order No. 4865. 

Administrative Rules of Montana, Title 16, Chapter 20, "Water Quality," 
Montana Department of Health and Environmental Sciences. 

Administrative Rules of Montana, Title 16, Chapter 8, "Air Quality," 
Montana Department of Health and Environmental Sciences. 

Wood Combustion Principles, Processes and Economics, David Tillman, ( 
Amadea J. Rossi, William Kitto, Academic Press 1981 

Feasibility Study for a Forest-Residue - Fueled Electric Generating 
Plant, EPRI CS-1819, TPS 79-742, May 1981 

Federal Energy Regulatory Commission (FERC) Order No. 69, Final Rule 
Regarding the Implementation of Section 210 of the Public Utility 
Regulatory Act of 1978, issued Feb. 19, 1980. 

Protection of Environment, 40 CFR 52 & 60 

Montana Renewable Energy Program, "1982 Guidelines for Preparing Grant 
and Loan Proposals," Montana Department of National Resources and 






Small Power Production 

Power Purchase Agreement 


The Montana Power Company 



Article Caption Page 

1. Term of Agreement 2 

2. Sale of Power 2-3 

3. Purchase Price and Method of Payment 

a. Energy - 3 

b. Capacity and Associated Energy 4 

c. Payments 4 

4. Notices 5 

5. Electric Services Supplied by Company 5-6 

6. Force Majeure 6-7 

7. Indemnity 7 

8. Liability and Insurance 8-9 

9. Liability; Dedication 9-10 

10. Several Obligations 10 

11. Waiver 10 

12. Assignment and Ownership 11 

13. Choice of Laws 11 

14. Governmental Jurisdiction and Authorization 12 

15. Captions 12-13 

16. Modification 13 

17. Terms and Conditions 13 

Appendix A 
General Contract Terms and Conditions 

A-l Definitions 

As used in this Agreement and the Appendices and Schedules attached 
hereto, the following terms shall have the following meanings: 

a. "Annual Capacity Factor" - The ratio, expressed as a per- 
centage, of the actual Energy output of a generating unit 
over a period of one year to the product of Capacity and 
8,760 hours; or if the period for which Capacity Factor is 
to be determined is less than one year, it will be the ratio 
of actual Energy output during the period to the product of 
Capacity and the number of hours in the period. 

b. "Annual Capacity Payment Adjustment" - The procedure per- 
formed at the end of each Contract Year for Sellers under 
the Long-Term Power Purchase tariff provision which reconciles 
payments made by Company to Seller during the Contract Year 
based upon estimated Capacity and Capacity Factor with 
payments that would have been made had they been based on 
actual Capacity and Annual Capacity Factor. 

c. "Associated Energy" - The amount of Energy expressed in 
kilowat thours provided to Company by Seller in conjunction 
with the supply of Capacity under Article 3 of this Agreement. 

Article 1 

Term of Agreement 

This Agreement shall be binding upon execution and shall remain 
in effect for a term consisting of the first partial year from 
the effective date of this contract until the June 30 immediately 

following such effective date and an additional period of 

from said June 30. 

Article 2 
Sale of Power 

a. Seller agrees to sell and deliver and Company agrees to pur- 
chase and accept delivery of Energy or Capacity and Associated 
Energy, subject to terms and conditions hereinafter set forth, 
in accordance with this Agreement and applicable Montana 
Public Service Commission approved rate schedules in effect. 
If Seller is a supplier of Capacity and Associated Energy 
hereunder, Seller hereby commits to a Contract Capacity of 

kW at an estimated Annual Capacity Factor in the 

initial Contract Year of %, subject to adjustment based 

on demonstrated Capacity and Annual Capacity Factor at the end 
of each Contract Year, and hereby affirms that this amount is 
no greater than the Capacity Rating of Seller's Facility. 

Seller elects, for purposes of computing payments hereunder, 
to supply Energy or Capacity and Associated Energy to Company 

in accordance with one of the following tariff and billing 
options : 

1. Short-Term Power Purchase 

a. Standard Payment 

b. Net Billing Option 

2. Long-Term Power Purchase 

a. Standard Payment 

b. Net Billing Option 

(Seller to initial one option only under either 
Category 1 or Category 2 above.) 

If Seller selects Long-Term Power Purchase option, then 
Contract Capacity and estimated Annual Capacity Factor must 
be specified. 

Article 3 

Purchase Price and Method of Payment 

a . Energy 

Company shall pay Seller for Energy delivered and accepted 
in accordance with the applicable Montana Public Service 
Commission approved rate schedule in effect for the period 
during which such deliveries are made. 


Capacity and Associated Energy 

If Seller elects to supply Capacity and Associated Energy, 
Company shall pay Seller for Capacity in accordance with the 
applicable Montana ' Public Service Commission approved 
rate schedule in effect for the period during which such 
deliveries are made. Company's obligation to pay Seller for 
Capacity and Associated Energy furnished to Company shall 
commence as of the Operation Date. 


Company shall make payments to Seller for deliveries in 
accordance with terms and conditions of this Agreement at the 
address of Seller specified in Article 4 hereof within 20 days 
after the monthly meter readings have been accomplished to 
determine the amount of net deliveries or direct deliveries 
into the system of Company from Seller during the billing 
period. Seller shall pay Company for Company's costs incurred 
hereunder or for Annual Capacity Payment Adjustment, at the 
address specified for Company in Article 4, in accordance 
with payment provisions specified hereunder or in accordance 
with Company's written statement. Should either Party fail 
to pay the other Party in full the charges reflected in such 
statements within the time allotted, the unpaid Party may 
deduct like amounts, adjusted for costs associated with short- 
term borrowings of the unpaid Party, from future payments to 
the other Party hereunder. 

Article 4 


All written notices under this Agreement shall ■ be directed as 
follows, and shall be considered delivered when deposited in the 
US Mail, first class postage prepaid, as follows: 

To Seller: 

To Company: Vice President, Operations 
The Montana Power Company 
40 East Broadway 
Butte, MT 59701 

Article 5 

Electric Services Supplied by Company 

This Agreement does not provide for any electric services by 
Company to Seller. If Seller requires any services from Company, 
Seller shall receive such service in accordance with Company's 
applicable electric tariffs on file with and authorized by the 
Montana Public Service Commission, and the Company may require 
as a condition of such service that Seller execute a separate 

agreement covering the sale of power by the Company to the Seller 
at the point of delivery defined herein. 

Article 6 
Force Majeure 

The term "Force Majeure" as used herein, means unforeseeable causes 
beyond the reasonable control of and without fault or negligence 
of the Party claiming Force Majeure. 

If either Party because of Force Majeure is rendered wholly or 
partly unable to perform its obligations under this Agreement, 
except for the obligation to make payments of money, that Party 
shall be excused from whatever performance is affected by the 
Force Majeure to the extent so affected provided that: 

1. the non-performing Party, within two weeks after the oc- 
currence of the Force Majeure, gives the other Party 
written notice describing the particulars of the condi- 
tion or occurrence which resulted in the Force Majeure; 

2. the suspension of performance is of no greater scope nor 
of longer duration than is required by the Force Majeure; 

3. obligations of either Party which arose before the occur- 
rence causing the suspension of performance are not 
excused as a result of the occurrence of Force Majeure; 

4. the non-performing Party uses its best efforts to remedy 
its inability to perform. This subparagraph shall not 
require the settlement of any strike, walkout, lockout 
or other labor dispute on terms which, in the sole judg- 
ment of the Party involved in the dispute, are contrary 
to its interest. It is understood and agreed that the 
settlement of strikes, walkouts, lockouts or other labor 
disputes shall be entirely within the discretion of the 
Party having difficulty. 

Article 7 
Indemni ty 

Each Party shall indemnify the other Party, its officers, agents, 
and employees against all loss, damage, expense and liability to 
third persons for injury to or death of person or injury to property, 
proximately caused by the indemnifying Party's construction, owner- 
ship, operation, or maintenance of, or by failure of, any of such 
Party's works or facilities used in connection with this Agreement. 
The indemnifying Party shall, on the other Party's request, defend 
any suit asserting a claim covered by this indemnity. The indem- 
nifying Party shall pay all costs that may be incurred by the 
other Party in enforcing this indemnity. 

Article 8 
Liability and Insurance 

Seller agrees to protect, indemnify and hold harmless Company, 
its directors, officers, employees, agents, and representa- 
tives, against and from any and all loss, claims, actions, or 
-suits, including costs and attorneys' fees, for or on account 
of injury, bodily or otherwise, to, or death of, persons, or 
for damage to, or destruction of property belonging to Company 
or others, resulting from, or arising out of or in anyway 
connected with the facilities on Seller's side of the Point of 
Delivery, or Seller's operation and/or maintenance, excepting 
only such injury or harm as may be caused solely by the 
fault or negligence of Company, its directors, officers, 
employees, agents or representatives. 

Prior to connection of Seller's generation equipment to Compa- 
ny's system, Seller shall secure and continuously carry in an 
insurance company or companies acceptable to Company compre- 
hensive general liability, bodily injury and property damage 
insurance . 

Such insurance shall include provisions that such policies 
shall not be cancelled or their limits of liability reduced 
without thirty (30) days' prior written notice to Company. A 
copy of each such insurance policy, certified as a true copy 
by an authorized representative of the issuing insurance 

company or, at the discretion of Company in lieu thereof, a 
certificate in form satisfactory to Company certifying to the 
issuance of such insurance, shall be furnished to Company. 
Initial limits of liability for all requirements under this 

Section (B) shall be $ single limit, which limit may 

be required to be increased with good cause by Company's giving 
Seller ninety (90) days' notice. 

c. In the event that Seller agrees to make Contract Capacity and 
Associated Energy sales to Company, Seller agrees to obtain 
insurance acceptable to Company against property damage or 
destruction in an amount not less than the cost of replacement 
of the Facility. Seller shall promptly notify Company of any 
loss or damage to the Facility. Unless the parties agree 
otherwise, Seller shall repair or replace the damaged or 
destroyed Facility. 

Article 9 
Liability; Dedication 

Nothing in this Agreement shall be construed to create any duty 
to, any standard of care with reference to or any liability to 
any person not a Party to this Agreement. 

No undertaking by one Party to the other under any provision of 
this Agreement shall constitute the dedication of that Party's 
system or any portion thereof to the other Party or to the 

public, nor affect the status of Company as an independent public 
utility corporation, or Seller as an individual or entity. 

Article 10 
Several Obligations 

Except where specifically stated in this Agreement to be otherwise, 
the duties, obligations and liabilities of the Parties are intended 
to be several and not joint or collective. Nothing contained in 
this Agreement shall ever be construed to create an association, 
trust, partnership, or joint venture or impose a trust or partnership 
duty, obligation or liability on or with regard to either Party. 
Each Party shall be individually and severally liable for its own 
obligations under this Agreement. 

Article 11 
Wa iver 

Any waiver at any time by either Party of its rights with respect 
to a default under this Agreement, or with respect to any other 
matters arising in connection with this Agreement, shall be made 
in writing. Such waiver shall not be deemed a waiver with respect 
to any subsequent default or other matter. 

Article 12 
Assignment & Ownership 

a. Neither Party shall Voluntarily assign its rights nor delegate 
its duties under this Agreement, or any part of such rights or 
duties, without the written consent of the other Party, except 
in connection with the sale or merger of a substantial portion 
of its properties including Interconnection Facilities which 
it owns, and any such assignment or delegation made without 
such written consent shall be null and void. Consent for 
assignment will not be withheld unreasonably. 

b. Energy and Capacity delivered to Company under this Agreement 
shall become the property of the Company at the Point of 
Interconnection and as such subject to the exclusive use of 
the Company for any purpose considered appropriate in its 
sole discretion. 

Article 13 
Choice of Laws 

This Agreement shall be construed and interpreted in accordance 
with the laws of the State of Montana, excluding any choice of 
law rules which may direct the application of the laws of another 
jurisdiction . 


Article 14 

Governmental Jurisdiction and Authorization 

This Agreement is subject to the jurisdiction of those governmental 
agencies having control over either Party or this Agreement. This 
Agreement shall not become effective until all required governmental 
authorizations and permits are first obtained and copies thereof 
are submitted to Company; provided, that this Agreement shall not 
become effective unless it, and all provisions thereof, is autho- 
rized and permitted by such governmental agencies without change 
or condition. 

This Agreement shall at all times be subject to such changes by 


such governmental agencies, and the Parties shall be subject to 
such conditions and obligations, as such governmental agencies 
may, from time to time, direct in the exercise of their jurisdic- 
tion. Both Parties agree to exert their best efforts to comply 
with all applicable rules and regulations of all governmental 
agencies having control over either Party or this Agreement. The 
Parties shall take all reasonable action necessary to secure all 
required governmental approval of this Agreement in its entirety 
and without change. 

Article 15 
C apt ions 


All indexes, titles, subject headings, section titles and similar 
items are provided for the purpose of reference and convenience 

and are not intended to be inclusive, definitive or to affect the 
meaning of the contents or scope of this Agreement. 

Article 16 

No modification of this Agreement shall be valid unless it is in 
writing and signed by both Parties hereto. 

Article 17 
Terms and Conditions 

This Agreement includes applicable Montana Public Service Commission 
approved rate schedules currently in effect and Appendix A 
General Contract Terms and Conditions, which are attached and 
incorporated by reference herein. 

IN WITNESS WHEREOF, the Parties hereto have caused this Agreement 
to be executed by their duly authorized representatives as of the 
last date hereinabove set forth: 


BY : BY : 

(Type Name) (Type Name) 


Appendix A 
General Contract Terms and Conditions 

Article Caption Page 

A-l Definitions 1-4 
A-2 Construction 

a. Land Rights 5 

b. Facility and Equipment Design and 

Construction 5-6 

c. Interconnection Equipment 7 
A-3 Metering 8 
A-4 Operation 

a. Facility and Equipment Operations and 

Maintenance 8-10 

b. Distortions 10-11 

c. Shortages 11 

d. Deliveries 11 

e. Communications 11 

f. Meters 11-13 

g. Delivery Reductions and Interruptions 13-14 

h. Scheduling 14 

i. Monthly Statements 14 

j. Adjustments 14-15 

k. Changes in Capacity Rating 15 

Appendix A 
General Contract Terms and Conditions 

A-l Definitions 

As used in this Agreement and the Appendices and Schedules attached 
hereto, the following terms shall have the following meanings: 

a. "Annual Capacity Factor" - The ratio, expressed as a per- 
centage, of the actual Energy output of a generating unit 
over a period of one year to the product of Capacity and 
8,760 hours; or if the period for which Capacity Factor is 
to be determined is less than one year, it will be the ratio 
of actual Energy output during the period to the product of 
Capacity and the number of hours in the period. 

b. "Annual Capacity Payment Adjustment" - The procedure per- 
formed at the end of each Contract Year for Sellers under 
the Long-Term Power Purchase tariff provision which reconciles 
payments made by Company to Seller during the Contract Year 
based upon estimated Capacity and Capacity Factor with 
payments that would have been made had they been based on 
actual Capacity and Annual Capacity Factor. 

c. "Associated Energy" - The amount of Energy expressed in 
ki lowat thours provided to Company by Seller in conjunction 
with the supply of Capacity under Article 3 of this Agreement. 

"Avoided Energy Cost" - The cost Company would have incurred 
for Energy supplies in the absence of Energy supplies avail- 
able to Company from Seller's Facility. 

"Avoided Capacity Cost" - The cost Company would have incurred 
for Capacity in the absence of Capacity supplied to Company 
by Seller. 

"Capacity" - The maximum net amount of electric power the 
Facility generates and delivers to Company at the high-voltage 
bus of the Company at the site of Facility, expressed in 
kilowatts (kW). 

"Capacity Rating" - The magnitude of Capacity Seller's 
Facility is capable of supplying. 

"Contract Capacity" - The amount of Capacity in kilowatts 
(kW) which Seller commits to supply to Company under Article 
3 of this Agreement. 

"Early Contract Termination" - The early termination of this 

"Contract Year" - A twelve month period of time commencing 
immediately after midnight on July 1 of any year and ending at 
midnight on June 30 of the following year. 

"Energy" - Electric energy supplied by Seller expressed in 
kilowatthours (kWh). 

"Facility" - That generation facility operated by Seller, and 
subject of this Agreement. 

"Force Majeure" - As defined in Article 6 of this Agreement. 

"Interconnection Equipment" - All equipment required to be 
installed solely to interconnect and accommodate delivery of 
power from Seller's generation Facility to Company's system 
including, but not limited to connection, transformation, 
switching, metering and safety equipment. Interconnection 
Equipment shall also include any necessary additions and/or 
modifications by Company to its system. 

"Long-Term Power Purchase" - The tariff provision which ap- 
plies to the production of a Seller who contracts to supply 
power to Company for a period of not less than four years. 

"Net Billing" - The optional billing arrangement under this 
Agreement which uses the net production of the Seller 
(monthly production minus monthly consumption where two 
meters are used; total reduction of "consumption" registra- 
tion from previous billing period where only one meter is 
used), if any, during any billing month, which net production 
serves as the bases for payment to Seller by Company in ac- 
cordance with applicable rate schedules. If consumption 
during the month exceeds production, then Seller is billed 
for net consumption at the applicable retail rate. 

"Operation Date" - The day commencing at 12:01 am, following 
the day during which all features and equipment of Facility have 

reached a degree of completion and reliability, such that they ( 
are capable of operating simultaneously to produce power. 

r. "Point of Delivery" - The location at which the electrical 
facilities of Seller and Company are connected. 

s. "Prudent Electrical Practice" - Those practices, methods and 
equipment, as changed from time to time, that are commonly used 
in prudent electrical engineering and operations to operate 
electrical equipment lawfully and with safety, dependability, 
efficiency and economy. 

t. "Seller's Property" - Facility and all Interconnection 
Equipment belonging to Seller. 


u. "Short-Term Power Purchase" - The tariff provision which 
applies to the production of a Seller who contracts to supply 
power to Company for a period of not less than one year. 

v. "Special Facilities" - Interconnection Equipment furnished by 
Company at Seller's request and expense, and other Company 
system additions or modifications required to accommodate 
deliveries from Facility to Company's system, also installed, 
operated and maintained at the expense of Seller. 

A-2 Construction 

Land Rights 

Seller hereby grants to Company for the term of this Agreement, 
and for such reasonable time thereafter as may be required 
to remove the Company's property, all necessary rights-of-way 
and easements to install, operate, maintain, replace and 
remove metering and other Special Facilities, including 
adequate and continuing access rights on property of Seller; 
and Seller agrees to execute such other grants, deeds or 
documents as Company may require to enable it to record such 
rights-of-way and easements. If any part of Company's facil- 
ities are to be installed on property owned by other than 
Seller, Seller shall, if Company is unable to do so without 
cost to Company, procure from the owners thereof, all necessary 
permanent rights-of-way and easements for the construction, 
operation, maintenance and replacement of Company's facilities 
upon such property in a form satisfactory to Company. At 
Seller's request and sole expense, Company shall, to the 
extent it is legally able, acquire necessary rights-of-way at 
such cost as may be agreeable to Seller. 

Facility and Equipment Design and Construction 

Seller shall design, construct, install, own, operate and 
maintain the Facility and all equipment needed to generate 
and deliver Energy or Capacity and Associated Energy specified 
herein, except for any Special Facilities constructed, installed 
and maintained by Company for Seller's benefit, which such 

Special Facilities shall be installed, operated and maintained 
at the expense of Seller. Such Facility and equipment shall 
meet all requirements of applicable codes and all standards 
of Prudent Electrical Practice. Seller also agrees to meet 
reasonable Company requirements for Seller's Facility and 
equipment. Seller shall submit all its Facility and equipment 
specifications to Company for review prior to connecting its 
Facility and equipment to Company's system. Company's review 
of Seller's specifications shall not be construed as confirming 
nor endorsing the design nor as any warranty of safety, dur- 
ability or reliability of the Facility or any of the equipment. 
Company shall not, by any reason of such review or failure to 
review, be responsible for strength, details of design, adequacy 
or capacity, successful operation or performance of Seller's 
Facility or equipment, nor shall Company's acceptance be 
deemed to be an endorsement of any Facility or equipment. 
Seller agrees to change its Facility and equipment as may be 
reasonably required by Company to meet changing requirements 
for construction, design, or operation of Company's system, 
and to make such required changes at Seller's expense. All 
changes in specifications, including new or additional equip- 
ment shall also be subject to Company's acceptance and approval 
as provided above. Seller shall interconnect its Facility 
with equipment of Company only after it has received from 
Company written acceptance of all Facility specifications and 
after it has received and complied with written requirements 
from Company for such interconnection. 

Interconne ction Equipment 

Seller shall construct, install, own and maintain Interconnec- 
tion Equipment as required for Company to receive Energy or 
Capacity and Associated Energy from Seller's Facility. Sel- 
ler's Interconnection Equipment shall be of sufficent size 
and capability to accommodate the delivery of Energy or 
Capacity and Associated Energy under this Agreement. Seller 
shall allow Company to review the characteristics and specifi- 
cations of all protective devices, and to establish require- 
ments for protective equipment ratings and settings and period- 
ic testing; provided, however, that neither such review nor 
the lack of such review by Company shall be construed as a 
warranty or endorsement of the safety, adequacy, or performance 
of Seller's Interconnection Equipment. In the event it is 
necessary for Company to install Special Facilities or other 
Interconnection Equipment or to alter its system for purposes 
of this Agreement, Seller shall reimburse Company for all of 
its costs associated therewith, including annual costs as- 
sociated with ownership, operation and maintenance; provided, 
however, that Seller will be provided with an estimate of all 
such costs and must approve of all such costs before required 
work by Company may begin; and provided further that arrange- 
ments for method and timing of payments to be made by Seller 
to Company for such costs will be mutually agreed upon among 
the Parties in advance of the time construction by Company is 
to begin. 

A- 3 Metering 

If Seller elects to receive payment under the Standard Pay- 
ment Option appropriate metering equipment capable of accurately 
measuring and recording or indicating flow of Energy in kilo- 
watthours, integrated demand for each hour if required, and, at 
the option of Company, reactive volt-ampere hour flow between 
Seller's Facility and Company's system, will be furnished and 
installed by the Company at the expense of Seller at a mutually 
agreeable location. Company may also in its sole discretion, 
install secondary meters at a mutually agreeable location 
within Seller's Facility for the purpose of enabling Seller 
to make telephone reports to Company as may be required. The 
location of metering equipment shall not necessarily signify 
location of division of ownership of facilities or Point of 
Delivery. Company shall own, maintain and test meters. All 
costs associated with the purchase, installation, ownership, 
maintenance, inspection and periodic testing of meters, and 
related administrative costs incurred by Company in metering 
Seller's generation shall be borne by Seller. 

A-4 Operation 

Facility and Equipment Operations and Maintenance 
Seller's Property shall meet the requirements of all applicable 
State and Local Laws. Prior to commencement of generation and 
interconnection of Seller's Facility with the system of the 
Company, Seller's Property shall be inspected and approved by 

the appropriate State and Local officials. Seller shall 
operate and maintain Facility in a safe manner and in accordance 
with the National Electrical Safety Code. 

Seller's Property shall include the following equipment to be 
installed, operated, and maintained in good working order by 

1. A lockable main disconnect switch which allows 
isolation of Seller's Facility from Company's system. 
Such disconnect switch will be located by mutual 
agreement of the Parties, and at all times will be 
accessable to and operable by qualified employees 
or agents of Company as well as Seller. 

2. An automatic disconnecting device which is designed 
to operate in conjunction with and in response to 
appropriate relays and protective devices. 

3. Relays and controls required by Company. 

4. Equipment as required to establish and maintain 
Facility generation operation in synchronism with 
Company's system. 

Seller shall operate and maintain its Facility and equipment 
according to Prudent Electrical Practices; the instantaneous 
reactive power consumed from the Company shall not exceed 
thirty-two percent (32%) of the real power being generated by 
the Facility; and the instantaneous reactive power delivered 

to the Company shall not exceed thirty-two percent (32%) of the 
real power being generated by the Facility. In the absence 
of compliance by the Seller with the above reactive power 
restrictions, then Company may, without incurring liability, 
disconnect Seller's Facility from Company's system. During 
such period of disconnection, Company's obligation to make 
payments "to Seller shall be suspended. 

If conditions on Company's system require, in the sole deter- 
mination of Company, a change in Company's system voltage at 
the Point of Delivery, Company will give no less than one 
hundred eighty (180) days notice to Seller of such change, 
and, at the expiration of the notice period, may make the 
required voltage change and require Seller to make necessary 
modifications to Seller's Interconnection Equipment, at 
Company's expense, to maintain compatibility with Company's 
modified system operating voltage level. If mutually agreed 
between Seller and Company, Company may make necessary modifica- 
tions to Seller's Interconnection Equipment, also at Company's 
expense . 


Seller shall remedy any harmonic distortion on Company's system 
attributable to the operation of Seller's Facility which may 
result in objectionable service to Company's other customers. 
If Seller's actions to remedy such harmonic distortions prove 
inadequate, then Company may, without incurring liability, 
disconnect Seller's Facility from Company's System. During s.uch 

occasions when the meters are to be inspected, tested, adjusted 
or reset. 

Company shall, at Seller's expense, inspect and test all meters 
supplied at Seller's expense upon their installation and at 
least once every two years thereafter. If requested to do so 
by Seller, Company shall inspect or test such meter more 
frequently than every two years, but the expense of such 
inspection or test shall be paid by Seller unless, upon being 
inspected or tested, such meter is found to register inaccu- 
rately by more than two percent of full scale, in which case 
the expense of testing will be borne by Company. Each Party 
shall give reasonable notice to the other Party of the time 
when any inspection or test shall take place, and that Party 
may have representatives present at the test or inspection. 
If such meter is found to be inaccurate or defective, it 
shall be adjusted, repaired or replaced, at Seller's expense, 
in order to provide accurate metering. 

If any meter (Company supplied or Seller supplied) fails to 
register, or if the measurement made by a meter during a test 
varies by more than two percent from the measurement made by 
the standard meter used in the test, appropriate adjustment 
shall be made correcting all measurements made by the inaccu- 
rate meter for: 

1. the actual period during which inaccurate measure- 
ments were made, if the period can be determined, or, 
if not, 

period of disconnection, Company's obligation to make payments 
to Seller shall be suspended. 


Seller agrees that, for any period during which the Company 
determines there is a shortage of supply of Energy or Capacity 
or both available to its system, Seller will, at Company's 
request, and within reasonable and safe limits on levels of 
production as determined by Seller, use its best efforts to 
provide requested Energy and/or Capacity and Associated Energy, 
and shall, if necessary, delay any maintenance periods. 


Seller shall deliver Energy or Capacity and Associated Energy 
under this Agreement to Company at the Point of Delivery. 


Company, through its system dispatcher, or other appropriate 
operating personnel, and Seller shall maintain operating 
communications in order to effectively accomplish system 
paralleling or separation, scheduled and unscheduled shutdowns, 
equipment clearances, requirements of Company for operation 
reports and other operating functions deemed necessary by 
Company . 


Ail meters used to determine the billing hereunder shall be 
sealed and the seals shall be broken only by Company upon 

2. the period immediately preceding the test of the 
meter equal to one-half the time from the date of 
the last previous test of the meter; provided, that 
the period covered by the correction shall not 
exceed six months. 

Each Party, after giving reasonable notice to the other Party, 
shall have the right of access to all metering and related 
records . 

Delivery Reductions and Interruptions 

Company shall not be obligated to accept deliveries from 
Seller, and may require Seller to interrupt or reduce deliveries 
of Energy or Capacity and Associated Energy, during periods of 
emergencies, Forced Outages, occurrence of operating conditions 
requiring such interruption or reduction as determined by 
Company, or to allow Company to install, maintain, repair, 
replace, remove or inspect equipment on any part of Company's 
system, or as otherwise required by Prudent Electrical 
Pract ices . 

Except in cases of emergency, where possible, either Party 
shall give reasonable notice to the other Party of the need 
to reduce or interrupt deliveries to Company from Seller's 
Facility, and with such notice the reason the reduction or 
interruption is required, and the probable duration of the 
condition or circumstance requiring such interruption or 
red uct ion . 

In the event of a Force Majeure affecting the ability of / 
either Party to perform as required by this Agreement, Seller 
shall not be obligated to deliver, and may curtail, interrupt 
or reduce deliveries of Energy or Capacity and Associated 
Energy to Company, and Company shall not be obligated to 
accept and may require Seller to curtail, interrupt or reduce 
deliveries of Energy or Capacity and Associated Energy. 

h . Schedul ing 

Prior to December 31 of each year, Seller shall prepare in 
writing and send to Company a proposed schedule of generation 
for each month of the ensuing eighteen (18) months beginning 
with January of the following year. Said schedule shall 
indicate the estimated times of operation, estimated amounts 
of production, anticipated shutdov:ns and scheduled maintenance 
periods . 

i . Monthly Statements 

Within 20 days following the end of each monthly billing 
period, Company shall send a statement to Seller showing the 
amount of Energy or Capacity and Associated Energy delivered 
to Company's system during the billing period, if any, the 
amount due Seller from Company in accordance with applicable 
Contract provisions and rate schedules, and a check for the 
amount due Seller for such billing period. 

j . Ad j ustme n t s 

In the event adjustments to statements are required as a 
result of corrected measurements made by inaccurate meters, 

_ 1 A - 

the Parties shall use the corrected measurements described in 
Article 9(f) to recompute the amounts due from or to Company 
for the Energy or Capacity and Associated Energy delivered 
under this Agreement during the period of inaccuracy. If the 
total amount, as recomputed, due from a Party for the period 
of inaccuracy varies from the total amount due as previously 
computed,' and payment of the previously computed amount has 
been made, the difference in the amounts shall be paid to the 
Party entitled to it within 30 days after the paying Party is 
notified of the recomputat ion . 

Changes in Capacity Rating 

The Capacity Rating of Seller's Facility (if applicable) under 
Article 3(a) is subject to change if for any reason the assured 
Capacity capability of Facility changes or is proven to be 
different than the amount indicated in Article 3(a). If 
Capacity capability changes or if Capacity capability is 
proven different, a new Capacity Rating and Contract Capacity 
amount shall be established for Facility, and such new amount 
shall be used for purposes of this Agreement in the place of 
the Contract Capacity amount originally indicated in Article 
3(a) . 

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